MX2013000292A - A method for treatment of subterranean sites adjacent to water injection wells. - Google Patents

Abstract

A method to improve the effectiveness of MEOR or bioremediation processes has been disclosed. In this method toxic chemicals accumulated in subterranean sites adjacent to the water injection wells are either dispersed or removed prior to introduction of microbial inocula for enhanced microbial oil recovery or bioremediation of these sites.

Description

METHOD FOR TREATMENT OF SUBTERRANEAN SITES ADJACENT TO WATER INJECTION WELLS Field of the Invention The invention relates to the field of improved oil recovery, microbial and bioremediation of underground contaminated sites. Specifically, it refers to methods for treating toxic chemicals accumulated in underground sites adjacent to water injection wells prior to the introduction of microbial inoculants for the recovery of improved, microbial, or bioremediation of these sites.

Background of the Invention Traditional oil recovery techniques that use only the natural forces present in an oil well site, allow the recovery of only a minor portion of crude oil present in an oil deposit. The oil well site generally refers to any location where wells have been drilled in an underground rock containing oil in an attempt to produce oil from that underground rock. An oil deposit typically refers to an underground oil deposit. Supplemental recovery methods such as flooding with water have been used to force or pass oil through the Ref .: 238288 underground location to the production well and thus improve the recovery of crude oil (Hyne, NJ, 2001, "Non-technical guide to petroleum geology, exploration, drilling, and production", 2nd edition, Pen Well Corp., Tulsa, OK, USA).

To meet the growing global demand on energy, there is a need to further increase the production of crude oil from petroleum deposits. An additional supplemental technique used to increase oil recovery from oil deposits is known as Enhanced Microbial Oil Recovery (MEOR) as described in U.S. Patent No. 7. , 484, 560. The MEOR, which has the potential to be an effective cost method for improved oil recovery, involves either stimulating the microorganisms of the natural oil reservoir or specifically injecting selected microorganisms into the Deposit of oil to produce metabolic effects that lead to the recovery of improved oil.

The production of oil and gas from underground oil deposits requires the installation of various equipment and pipes on the surface or in the underground sites of the oil deposit that come into contact with corrosive fluids in gas and oil field applications. Thus, oil recovery is facilitated by preserving the integrity of the equipment needed to provide water for water injection wells and to transport oil and water from production wells. As a result, corrosion can be a significant problem in the petroleum industry due to the cost and downtime associated with the replacement of corroded equipment.

Sulfate - reducing bacteria (SRB), which produce hydrogen sulfide (H2S), are among the biggest contributors to the. corrosion of ferrous metal surfaces and oil recovery equipment. These microorganisms can cause the formation of acid substances, corrosion and clogging and in this way can have negative impact on a MEOR or a bioremediation process. Bioremediation refers to processes that use microorganisms to clean oil spills or other contaminants from either the surface or the underground sites of the soil.

To combat corrosion, corrosion inhibitors, which are chemicals that decrease the corrosion rate of a metal or alloy and are often toxic to microorganisms, are used to preserve water injection equipment and oil recovery equipment. such wells. In the practice of the present invention, a water injection well is a well through which water is pumped down into a petroleum producing tank for pressure maintenance., water flooding or improved oil recovery. Significant classes of corrosion inhibitors include compounds such as: inorganic and organic corrosion inhibitors. For example, organic phosphonates, organic nitrogen compounds, organic acids and their salts and esters (Chang, R. J. et al., Corrosion Inhibitors, 2006, Specialty Chemicals, SRI Consulting).

U.S. Patent Application Publication No.2006 / 0013798 discloses the use of bis-quaternary ammonium salts as corrosion inhibitors to preserve metal surfaces in contact with fluids to prolong the life of these fixed assets.

U.S. Patent No. 6,984,610 describes methods for cleaning waste from oil sludge and drilling mud from well cuts, drilling of surface oil well and production equipment through the application of acids, fracturing with pressure and microemulation based on acid for the recovery of improved oil.

WO2008 / 070990 describes the pre-conditioning of oil wells using such pre-conditioning agents. such as methyl ethyl ketone, methyl propyl ketone and methyl tertiary-butyl ether in the injection water to improve oil recovery. Mechanisms such as modification of oil viscosity in the deposit and stimulation of heavy oil were attributed to this method.

US2009 / 0071653 discloses the use of surfactants, caustic agents, antifouling agents and abrasive agents to prevent or remove the accumulation of fluid films on the processing equipment to increase the capacity of the well.

Studies indicate that the long-term addition of chemicals or agents used to control undesirable events such as corrosion, scaling, microbial activities, and foaming in the water supply of a water injection well did not lead to their accumulation in concentrations high enough to adversely affect the microorganisms used in the MEOR (Carolet, JL, in: Ollivier and Magot ed., "Petroleum Microbiology", chapter 8, pages 164-165, 2005, ASM press, Washington, DC).

However, the viability of the microorganisms used in the processes of MEOR or bioremediation is of great interest. It may be desirable to modify the MEOR or bioremediation treatments such that the viability of the microorganisms used is maintained by all these processes such that the MEOR or bioremediation processes become more effective.

Brief Description of the Invention The present disclosure relates to a method for improving the effectiveness of a MEOR or bioremediation process by detoxifying underground sites adjacent to oil wells, where the wells have previously been treated with corrosion inhibitors prior to inoculation of the required microorganisms for MEOR or bioremediation.

In one aspect, the present invention relates to a method comprising in order the steps of: a) treating an underground site in an area adjacent to a water injection well with a detoxification agent; Y b) add an inoculum of microorganisms where the microorganisms comprise one or more species of: Co ammonia, Fusibacter, Marinobacteriu, Petrotoga, Shewanella, Pseudomonas, Vibrio, Petrotoga, Thauera, and Microbulbifer useful in the recovery of improved oil, microbial to the well water injection; where prior to the treatment of (a) at least one corrosion inhibitor and its degradation products, if present, have been absorbed in the area and have accumulated at concentrations that are toxic to the microorganisms used in the recovery processes of improved oil, microbial, in order to form a toxic zone.

Brief Description of the Figures Figure 1 is the schematic representation of a water injection well and the underground sites adjacent to the water injection well. (1) is the injection water flow in the well casing (7), (2 and 3) are layers of rock, (5) are perforations in the casing, (4) are fractures in the rock layer, ( 6) is the face or face of the rock layer made by the well drilling, (7) is the well casing, (8) is one side of the zone supplied with water that is axi-symmetric with the injection well. , shown by a box of dashes in the rock layer (3).

Fig. 2 is the schematic representation of a model system used to simulate the formation of a toxic zone. (9) is a long thin tube; (10) is a pressure vessel for narrowing the thin tube; (11 and 12) are the opposite ends of the pressurized container; (13) is a pump; (14) is the feed tank; (15) is the water inlet for the pressure vessel; (16) is the back pressure regulator; (17) is the supply of high pressure air; (18) is an inlet fitting that connects the thin tube inside the pressure vessel to the pump and the pressure transducers; (21) are output fittings that connect the thin tube inside the pressure vessel to the backpressure regulator and the low side of the differential pressure transducer; (19) is a differential pressure transducer; and (20) is an absolute pressure transducer.

Fig. 3 represents the titration of the amine coated sand; the symbols ? represent amine in sand solution coated with amine and symbols? they represent the first derivative of the titration curve (central differences).

Fig. 4 represents the titration of brine and sand with HC1 1N; the symbols | represent the pH of brine # 1 with 10 grams of sand; the symbols ? they represent the pH of brine # 1 only; the symbols § | represent the pH slope of # 1 brine with 10 grams of sand, and the symbols? represent the pH slope of # 1 brine only.

Fig. 5 represents titration of brine and sand contaminated with amine with 10% nitric acid; the symbols ? represent the concentration of amine observed in solution for a given pH.

Fig. 6 represents the titre of brine and the core or core sand with 10% acetic acid; the symbols ? represent the concentration of amine observed in solution for a given pH.

Detailed description of the invention In one aspect, the present invention is a method for detoxifying corrosion inhibitors, and their degradation products, if present, that have accumulated in an underground site adjacent to a water injection well of an oil well site. . Applicants have found that oil recovery processing aids such as corrosion inhibitors, for example, can accumulate in the area adjacent to the water injection well and accumulate at concentrations that are toxic to the microorganisms used in the MEOR or bioremediation. . As the term is used herein, "detoxifying" or "detoxifying" a water injection site means the removal or reduction of toxicity caused by corrosion inhibitors and their degradation products to microorganisms to allow their growth and activity of microorganisms, used in the MEOR or bioremediation.

For the purpose of the present invention, the term "toxic zone" refers to an underground site adjacent to the water injection well comprising toxic concentrations of agents such as corrosion inhibitors or their degraded products which have adverse effects on growth and the metabolic activities of the microorganisms used in the MEOR and / or bioremediation. These agents can bind to sand, rock, clays in the rock and / or oil that is attached to the rock creating a toxic zone. A toxic agent, as the term is used herein, is any biological chemical agent that adversely affects the growth and metabolic functions of the microorganisms used in the MEOR and / or bioremediation.

Figure 1 is a schematic representation of an underground site adjacent to a water injection well. The injection water (1) flows in the well casing (7) that is inside the well borehole (6) drilled through rock layers (2 and 3). There is a space between the well tubing (7) and the face (6) of the rock layer made by the well drilling (5). The rock layer (2) represents the impermeable rock above and below an impermeable rock (3) that contains or traps the oil. The injection water (1) flows down the well tubing (7) and passes through the perforations (5) in the tubing (7) and in the fractures (4) in the permeable rock (3). This injection water then flows through the permeable rock layer (3) and displaces the oil from an area supplied with water (8) adjacent to the well bore. This zone extends radially out of the well bore (6) in all directions in the permeable rock layer (3). While the volume of permeable rock (3) encompassed by the dashed line (8) is illustrated only on one side of the well drilling, this really exists on all sides of the well drilling. This area supplied with water represents the underground site adjacent to the water injection well.

The corrosion inhibitors, together with their degradation products, if present, which can accumulate at levels that are toxic to the microorganisms used in the MEOR are, for example: inorganic corrosion inhibitors such as chlorine, hypochlorite, bromine, hypobromide and chlorine dioxide. Additional cumulative, potentially toxic, inorganic corrosion inhibitors used to combat corrosion caused by SRB include, but are not limited to: hydrazine, anthraquinone, phosphates, sodium sulfite and salts containing molybdate, chromium or zinc (Sanders and Sturman, chapter 9, page 191, in: "Petroleum microbiology" page 191, supra and Schwermer, CU, and collaborators, Appl. Environ. Microbiol., 74: 2841-2851, 2008).

Organic compounds used as corrosion inhibitors that can accumulate to form a toxic zone include: acetylenic alcohols, organic azoles, gluteraldehyde, tetrahydroxymethyl phosphonium sulfate (THPS), aciclohem bistiocyanate, docecilguanine hydrochloride, formaldehyde, chlorophenols , organic oxygen scavengers and various non-ionic surfactants (surfactants).

Other organic corrosion inhibitors that may accumulate to form a toxic zone include, but are not limited to: organic phosphonates, organic nitrogen compounds including primary, secondary, tertiary or quaternary ammonium compounds (hereinafter referred to generically as "amines") ") organic acids and their salts and esters, carboxylic acids and their salts and esters, sulfonic acids and their salts.

Applicants have determined that corrosion inhibitors can accumulate by adsorption in or on the underground site (eg, rock, clay, sandstone, unconsolidated stone or limestone) or within oil that has been trapped in the underground site of oil deposit. The long-term addition of these chemicals results in their accumulation and formation of a toxic zone in underground sites adjacent to the water well with adverse effects on microbial inocula proposed for applications of MEOR and / or bioremediation.

A model system to simulate the formation of a toxic zone can be used to study its effects on the survival of microorganisms. For example, a model system called a thin tube can be arranged and packaged with core sand from an oil well site. The model system as described herein can be arranged using pipe, valves and accessories compatible with the crude oil or hydraulic solution used that can withstand the pressure range applied during the process. An absolute pressure transducer, differential pressure transducer and back pressure regulator, for example, made by Cole Plamer (Vernon Hill, IL) and Serta (Boxborough, Mass), are used in the model system and are commercially available.

The model toxic zone can be established by using amine solutions and / or amine mixtures and deflasking them through a tube packed with core sand from an oil reservoir. Other corrosion inhibitors suitable for use in a model construction may comprise organic phosphonates or anthraquinone or phosphates. The concentration of the corrosion inhibitors used to create the model toxic zone can be from 0.01 to 100 parts per million.

The detoxification of the toxic zone in either the model system or in an underground site adjacent to a water injection well involves the degradation, desorption and / or dispersion of chemical substances or toxic agents accumulated using detoxification agents. The term "detoxification agent" therefore refers to any chemical substance that either disperses or destroys the chemical substances and toxic agents described herein and renders them non-toxic to microorganisms.

The treatment of a toxic zone in an underground site adjacent to a water injection well with a detoxification agent is carried out by any method for introducing a chemical substance into an underground site which is well known to one skilled in the art. Commonly the treatment is by introducing a composition containing a detoxification agent into the well as shown in the diagram of Figure 1 for injection water (1). The composition of detoxification agent flows through the well tubing 7), through the perforations (5), and in the fractures (4) in the permeable rock layer (3) in the area supplied with water (8) . This is the area adjacent to a water injection well where a toxic zone can be formed and treated by the detoxification agent.

Detoxification of chemicals accumulated in the toxic zone can be achieved by using a degradation agent. A degradation agent, as the term is used herein, is an agent that destroys or aids in the destruction of toxic agents found in the toxic zone. The degradation agents may include, for example, strong oxidants that chemically react with corrosion inhibitors, when added to the injection water flowing in the toxic zone, to degrade them into less toxic or non-toxic products. The degradation agents include strong oxidizing agents such as, for example, nitrates, nitrites, chlorates, perchlorates and chlorites.

Detoxification of chemicals accumulated in a toxic zone can also be achieved by using a dispersing agent. A dispersing agent as the term is used herein, includes any chemical substance that causes the toxic agents absorbed to be removed from the deposit rock and / or deposit sand in a toxic zone and solubilizes them in the water during the flooding with water in order to allow the dispersion and natural diffusion to reduce the concentration where it is not toxic for a longer time to the microorganisms of the MEOR or remediation.

In one embodiment, a dispersing agent includes any chemical substance that lowers the pH of a solution, ionizes amines and solubilizes them in water during the flood with water and allows dispersion and natural diffusion to decrease the concentration where it is not toxic for a longer time to the microorganisms of the MEOR or bioremediation. For example, amines are mainly non-reactive under moderate conditions, however, they become ionized at lower pH. Thus, the treatment of amines with an acid increases their solubility and releases them from oil and / or rocks and disperses them from the toxic zone. The solubilized amines can therefore enter the water that flows through the well. A combination of radial flow, dispersion and desorption can allow the solubilized amines to be diluted and dispersed over a large area of at least 3 meters to approximately 7 meters (at least 10 to approximately 200 feet)) of the oil well. After the dilution and dispersion of the amines over a much larger area, their concentrations within the underground site of the well have consequently been reduced to non-toxic levels for the microorganisms of the MEOR or bioremediation. In another embodiment, the hydrogen peroxide can be added to the toxic zone, both as a degradation agent and as a dispersing agent, from about 1,000 parts per million to 70,000 parts per million volume of water. In another embodiment, perchlorates, both as a degradation agent and as a dispersing agent, may be added from about 1 part per million to about 10,000 parts per million.

In another embodiment, any acid capable of lowering the pH can be used at least 1 unit lower than the equivalence point of the amine (as measured in the Examples below). The acid used to ionise the amines may include, but is not limited to, nitric acid, acetic acid, oxalic acid, hydrofluoric acid and hydrochloric acid. The acid can be added from about 0.1% by weight to about 20% by weight of the water that is being pumped into the toxic zone.

In a MEOR process, an inoculum of viable microorganisms is added to the water that is injected into a water injection well (see Figure 1). The term "inoculum of microorganisms" refers to a composition that contains viable microorganisms. These microorganisms colonize, that is, grow and spread, in the underground sites adjacent to the water injection well to promote MEOR. Oil recovery can be enhanced by actions of microorganisms such as the release of oil from the rock and / or underground sand, and by forming plugged biofilms that will increase the sweeping efficiency in the recovery of secondary oil with flooding with water.

The microorganisms useful for this application may comprise classes of facultative aerobes, bound anaerobes and denitrifiers. Preferred for use in underground sites are microorganisms that are effective under anaerobic denitrification conditions. The inoculum may comprise only one particular species or may comprise two or more species of the same genera or a combination of different genera of microorganisms.

The inoculum may be produced under aerobic or anaerobic conditions depending on the particular microorganism (s) used (s). Techniques and various growth media suitable for the growth and maintenance of aerobic and anaerobic cultures are well known in the art and have been described in "Manual of Industrial Microbiology and Biotechnology" (AL Demain and NA Solomon, ASM Press, Washington, DC, 1986) and "Isolation of Biotechnological Organisms from Nature", (Labeda, DP ed. P 117-140, McGraw-Hill Publishers, 1990).

The inoculum of microorganisms is added to an underground site by any method for the introduction of microorganisms that is well known to one skilled in the art. Typically the inoculum is added to the water injection well as a part of the injection water (1) that is introduced into the well tubing (7) as shown in Figure 1.

Examples of microorganisms useful in the present method include, but are not limited to, one or more species of the following genera: Comamonas, Fusibacter, Marinobacterium, Petrotoga, Shewanella, Pseudomonas, Vibrio, Thauera, and Microbulbifer. In one embodiment the microorganism used in the present method is selected from one or more of Territorial Comamonas, Fusibacter paucivorans, Marinobacterium georgíense, Petrotoga miotherma, Shewanella putrefaciens, Pseudomonas stutzeri, Vibrio alginolyticus, Thauera aromatic, Thauera chlorobenzoica and Microbulbif r hydrolyticus.

In one embodiment an inoculum of Shewanella putrefaciens LH4: 18 (ATCC PTA-8822), described in U.S. Patent 7,776,795, can be used in the present method. In another embodiment Pseudomonas stutzeri LH4: 15 (ATCC PTA8823), described in the United States Patent Application Publication of Common Property and co-pending No. US20090263887, may be used in the present method. In another Tharana aromatic modality AL9: 8 (ATCC 9497), described in the United States Patent Application Publication of Common Property and co-pending No. 20100078162, may be used in the present method.

Examples The present invention is further defined in the following Examples. It should be understood that these Examples, while indicating preferred embodiments of the invention, are given by way of illustration only. From the above discussion and these Examples, one skilled in the art can ascertain the essential characteristics of this invention, and make various changes and modifications to the invention to adapt it to various uses and conditions.

General methods Chemical substances and materials All reagents, and materials used for the growth and maintenance of microbial cells were obtained from Aldrich Chemicals (Milwaukee, Wl), DIFCO Laboratories (Detroit, MI), GIBCO / BRL (Gaithersburg, MD), or Sigma Chemical Company (St. Louis, MO), unless otherwise specified.

Analysis of amines The concentration of amines, in the media and water, was analyzed by gas chromatography (GC, for its acronym in English). An Agilent Model 5890 GC (Agilent, Wilmington, DE) equipped with a flame photoionization detector and a division / non-division injector, a DB-FFAP column (30 meters long x 0.32 millimeters (mm) deep x 0.25 micrometers of particle size). The team had an Agilent ALS Autoinjector, Model 6890 Series with a 10 milliliter syringe (mi). The system was calibrated using a sample of N, -Dimethyl-1-Dodecanoamine (Aldrich). Helium was used as the carrier gas. A temperature gradient of 50 degrees Celsius (° C) at 250 ° C was used in an increase of 30 ° C per minute (min). The retention times (in minutes, min) for several chemical substances of interest included: N, N-Dimethyl-1-Dodecanoamine (8.08 min); N, -Dimethyl-1-Tetradecanoamine (8.85 min); , N-Dimethyl-1-Hexadecane-amine (9.90 min); N, N-Dimethyl-l-Octadecanoamine (10.26 min) and N-Methyl, N-Benzyl-l-Tetradecanoamine (11.40 min).

Example 1 Establishment of a toxic zone in sand of an oil well that uses a mixture of amines in a model system A sample of the sand obtained from the Schrader Bluff formation at the Milne Pont Unit of the Alaska North Slope was cleaned by washing with a solvent consisting of a 50/50 (volume / volume) mixture of methanol and toluene. The solvent was subsequently drained and then evaporated from the sand to produce clean, dry, flowing sand. This sand was sieved to remove the particles with less than one micrometer in size and then packed hermetically in a long flexible thin tube (9) of 121.92 cm (four feet) and compacted by vibration using a laboratory recorder. Both ends of the thin tubes were covered to keep the sand in these. The complete apparatus is shown in Figure 2. The pipe that can hold the amount of pressures used in the thin tube was connected to the end caps. The thin tube (9) was mounted in the pressure vessel (10) with the pipe passing through the ends (11 and 12) of the pressure vessel using pressure fittings (18 and 21). Additional accessories and tubing were used to connect the inlet of the thin tube (11) or a pressure pump (13) and a supply tank (14).

Additional accessories and tubing connected to the inlet of the thin tube to an absolute pressure transducer (20) and the high pressure side of a differential pressure transducer (19). The fittings and tubing connected the outlet of the thin tube (12) to the low pressure side of a differential pressure transducer (19) and to a back pressure regulator (16). The. signals from the differential pressure transducer and the absolute pressure transducer were taken to a computer and the pressure readings were inspected and recorded periodically. The pressure vessel (10) around the thin tube was filled with water through a water hole (15). This water was then pressurized slowly with air (17) at a pressure of approximately 0.72 megapascal (105 pounds per square inch) (psi) while brine # 1 from the feed tank (14) (Table 1) flowed through the tube thin and left the thin tube through the feedback regulator (16). This operation was performed such that the pressure in the thin tube was always 0.034-0.137 megapascals (5 to 20 psi) below the pressure in the pressure vessel (10).

TABLE 1 Brine Ingredients # 1 (brine without nutrient-gram per liter (gr / L) of tap or piped water NaHC03 1.38 grams (gr) CaCl2 * 6H20 0.39 gr MgCl2 * 6H20 0.220 gr KC1 0.090 gr NaCl 11.60 gr NaHC03 1.38 gr Metals in quantities very small 1 mi Vitamins in amounts very small 1 mi gr (= 10 parts per million (ppm) of P0) NH4C1 0.029 gr (= 10 ppm NH4) Acetate 0.2 gr (200 ppm acetate) The pH of brine # 1 was adjusted to 7.0 with either HCl or NaOH and the solution was sterilized on a filter.

TABLE 2 Once the pressure inside and outside the thin tube was established, a pore volume of crude oil from an oil reservoir of the Milne Point Unit of the Alaskan North Slope was pumped into the thin tube. This process was carried out in several hours (h). Once the oil had saturated the sand in the thin tube and was observed in the effluent, the flow stopped and the oil was allowed to age in the core sand for 3 weeks. At the end of this time, brine # 1 was pumped through the thin tube at an expense of -1.5 - 3.5 milliliters per hour (ml / h) (~ 1 pore volume every 20 h). The samples were taken from the effluent and then the concentration of the natural microflora was determined.

After 51 pore volumes through the thin tube the concentration of natural microflora in the system was approximately 1 x 107 colony forming units per milliliter (CFU / ml). At this point, a mixture of amines (then in the present amine / brine mixtures) was added at a concentration of 150 ppm to the # 1 brine. The approximate composition of the amines mixture (Table 2) consisted of 7 different amine components that were identified. Five were identified by Mass Spectrometry (Agilent Technologies, Inc. Santa Clara, CA) as NN-dimethyl-1-dodecanoamine, NN-dimethyl-1-tetradecane-amine, NN-dimethyl-methano-thioamide, caprolactam and N- methyl-N-benzyl-1-tetradecanoamine. Two of the components were identified as amines but the specific chemical formulas could not be assigned to these because the Spectral Mass Fragmentation patterns could not be deciphered. These are labeled in Table 2 as "minor amine" and "other amine". The analysis of the thin tube effluent did not indicate the presence of any of the amines in it. The experiment was continued by pumping 150 ppm of the amine mixture in the # 1 brine through the thin tube.

After 77 pore volumes of the # 1 brine mixture with 150 ppm amines mixture was pumped into the thin tube, no amines were observed in the effluent.

After 80 pore volumes of the # 1 brine mixture with 150 ppm amines mixture was pumped into the thin tube, a total of about 1 g of the amines mixture has flowed through the thin tube. At this point, 80 ppm of amines was finally observed in the effluent of the thin tube. This very long delay in observing the amines in the effluent means that virtually all the amines have been trapped in the thin tube. Furthermore, at this time, no natural microflora could be observed in the effluent, which indicates that the thin tube has become quite toxic to kill all the existing microflora. At this point, the pumping of brine # 1 without amines was initiated in an attempt to wash the amines out of the thin tube and to make it less toxic.

After 24 pore volumes of # 1 brine without amines have been pumped through the thin tube, 51 ppm of amines was detected in the effluent. The thin tube was then inoculated with a pore volume of Shewanella putrefaciens (ATCC PTA-8822) at a concentration of approximately 1 x 109 CFU / ml. This inoculation was not allowed to remain in the thin tube. In contrast, brine # 1 without amines was rinsed through the thin tube immediately after inoculation. Consequently the microbes resided in the thin tube only a few hours during transit through it. Thus, it was anticipated that the concentration of microorganisms in the effluent could be measured in the effluent eluted by the thin tube. However, remarkably no microorganisms (representing approximately a 9 log kill) were detected in the thin tube effluent despite the short residence time of the inoculum in the thin tube. This experiment confirmed that a toxic zone has been established in the thin tube. In a continuous attempt to detoxify the thin tube, the # 1 brine alone was pumped continuously through it.

After 79 pore volumes of the # 1 brine without amines have been pumped through the thin tube, the concentration of amines in the thin tube effluent was measured at 30 ppm. The thin tube was inoculated with another pore volume of Shewanella putrefaciens (in 1 x 109 CFU / ml). The CFU / ml in an effluent sample was approximately 1 x 104 which shows more than one 5 log extermination of this microorganism that has occurred immediately after inoculation. This experiment emphasized the continuous toxic effect of the amines despite prolonged washing of the tube with the # 1 brine solution without amines.

After 108 pore volumes of # 1 brine without amines have been pumped through the thin tube, the concentration of amine in the effluent was measured at 5 ppm. The thin tube was inoculated with an additional pore volume of Shewanella putrefaciens containing 1 x 109 CFU / ml. The CFU / ml in the sample of effluent in the thin tube immediately after inoculation indicated an extermination of 4-5 log of this microorganism despite the prolonged washing with # 1 brine without amines and the decrease in the concentration of amines in the effluent. This result also confirmed the continuous toxic effect of the mixture of the amines accumulated in the thin tube.

After 143 pore volumes of the # 1 amines-free brine have been pumped through the thin tube an inexpensive odorless mineral oil (OMS) pore volume (Parks OMS, Zinsser Co., Inc., Somerset Jew Jersey # 2035 CAS # 8052-41-3) was pumped through the thin tube in an attempt to remove the remaining mixture of amines. After this washout with OMS, the pumping of the # 1 brine without amine through the thin tube was continued.

After 143 pore volumes of the # 1 brine without amines were pumped through the thin tube, the concentration of amines in the effluent was measured at 4 ppm and the thin tube was inoculated with an additional pore volume of Shewanella putrefaciens (1 x 109 CFU / ml). A count of microorganisms in the sample of the effluent of the thin tube showed an extermination of 2 -3 log (99 to 99.9%) despite the washout with OMS and the prolonged washing with the brine # 1 without amines. These results confirmed that the toxic zone in the thin tube was still virtually exterminating all the microorganisms added to the tube.

After 168 pore volumes of the # 1 non-amine brine has been pumped through the thin tube, a pore volume of a 10% HC1 solution in water was pumped through the thin tube to remove the amines. After this acid wash, the # 1 non-amined brine was continuously pumped through the thin tube.

After the acid wash treatment, 2 additional pore volumes of the # 1 non-amine brine was pumped through the thin tube and the concentration of amines in the effluent was measured at 0.5 ppm. The thin tube was then inoculated with an additional pore volume of Shewanella putrfaciens (1 x 109 CFU / ml). The CFU / ml in the effluent showed approximately an extermination of 0.4 log of this microorganism. These results underlined or accentuated the survival of more microorganisms after the acid wash of the thin tube and the effectiveness of using an acid to detoxify the toxic zone in the thin tube. Table 3 below summarizes the results of the various tests described in the above.

TABLE 3 Summary of the amount of amine observed in the thin tube effluent and the fraction of the killed microorganisms (log extermination) during residence in thin tube. PV = pore volume; nd = not detected EXAMPLE 2 REMOVAL OF N, N-DIMETHYL-1-DQDECANAMINE FROM SAND THROUGH OF IONIZATION IN LOW PH USING HYDROCHLORIC ACID 38 milligrams (mg) of N, N-Dimethyl-1-Dodecanamine (later referred to herein as "the amine") was added to 10,210 g of Pentane. This solution was added to 10.1845 gr of specific sand layers (Oa and Ob) obtained from the Schrader Bluff formation of the Milne Point Unit of the Alaskan North slope. The oil content in the sand was first removed using a mixture of methanol and toluene (50/50, volume / volume) as solvent washes. The solvent mixture was subsequently evaporated out of the sand to produce clean, dry, flowable sand. This sand was mixed with the amine and pentane solution to produce a suspension. This suspension was thoroughly mixed and the oil evaporated leaving the amine on the sand (hereinafter referred to as sand / amine mixture). 100 ml of brine # 2 (the recipe is shown below) was added to the sand / amine mixture to create the sand / amine / brine mixture. The initial pH of the sand / amine / brine mixture was 8.4. The concentration of the amine in the water should have been 380 ppm if all the amine dissolved in the # 2 brine. Analysis of a sample of the sand / amine / brine mixture by GC did not reveal the presence of any of the amines in the test sample (ie, the amine concentration was ~ <1 ppm). The fact that the amine was not detected accentuated its strong bond to the sand particles. 0.1 ml of normal HCl 1 (N) was added to this solution, and the pH and amine concentration were measured again. This step was repeated several times and the results of the analyzes are shown both in Table 4 and in Figure 3. The complete ionization and solubilization of the amine in the water was observed at pH below -6.0. This is a surprising discovery since the pKa of HC1 is -6.2 (Langes Handbook of Chemistry, 1st edition, page 8.14, 1992, McGraw-Hill, Inc., New York). Therefore, the concentration of HCl required for this step to completely ionize the amine and remove it from the toxic sand can also be reduced several orders of magnitude from the 10% concentration used in this example. The data underscore the remarkable efficiency of an acid in the ionization and removal of the amine from the sand.

Composition of brine # 2 (gr / L deionized water) NaHC03 1.38 gr CaCl2 * 6H20 0.39 gr MgCl2 * 6H20 0.220 gr KC1 0.090 gr NaCl 11.60 gr TABLE 4 Amine concentration measured in Example 2 shows N, N-dimethyl-1-first pH HCL 1 N (mi) dodecanamine derivative (change (ppm) in the amine / change effluent of in pH) thin tube Titration of 0.00 8.14 0.00 standard amine Titration of 46.41 63.75 7.37 0.10 amine 1 Titration of 59.29 63.42 7.21 0.10 amine 2 Titration of 67.97 24.34 7.03 0.10 amine 3 Titration of 74.38 160.35 6.59 0.10 amine 4 Titration of 212.28 412.18 6.13 0.10 amine 5 Titration of 288.72 679.86 6.07 0.10 amina 6 Titration of 273.47 -148.78 6.04 0.05 amine 7 shows N, N-dimethyl-1-first PH HCL 1 N (mi) dodecanamine derivative (change (ppm) in the amine / change effluent of in pH) thin tube Titration of 275.33 119.35 5 98 0.05 amine 8 Titration of 303.31 65.90 5 79 0.05 amine 9 Titration of 314.21 15.17 5 39 0.05 amine 10 Titration of 328.48 3.24 4 13 0.05 amine 11 Titration of 321.33 11.80 3 19 0.05 amine 12 Titration of 342.88 47.42 2 91 0.05 amine 13 Titration of 342.67 -6.52 2 74 0.05 amine 14 Titration of 340.92 79.86 2 61 0.05 amine 15 Titration of 369.02 80.22 2 41 0.10 amine 16 shows N, N-dimethyl-1-first PH HCL 1 N (mi) dodecanamine derivative (change (ppm) in the amine / change effluent of in pH) thin tube Titration of 368.19 2.25 2 27 0.10 amine 17 Titration of 369.54 7.51 2 18 0.10 amine 18 Titration of 369.47 0.12 2 10 0.10 amine 19 Titration of 369.56 2 04 0.10 amine 20 EXAMPLE 3 CAPACITY OF THE SAND TO NEUTRALIZE THE ACID A. Titration of brine # 2 in the absence of sand The intent of this experiment was to determine the capacity of the sand described in Example 2 to neutralize the proposed HCl to ionize the amine accumulated in the sand.

To adjust a control test, 100 ml of brine # 2 was titrated with 1 N HCl at an initial pH of 8.1. An aliquot (0.1 ml) of 1N HCl was added to brine # 2 and the pH was measured. The addition of HCl was repeated several times and the pH was measured after each addition. The results of these analyzes are shown both in Table 5 and Figure 4. The data indicated that approximately 2.25 milliequivalents of HCl were necessary to achieve the equivalence point of approximately pH 4 corresponding to approximately 100% recovery of the carbonate present in the brine # 2.

TABLE 5 Titration of brine # 2 synthetic injection in the absence of the amine B. Titration of brine # 2 with sand 100 ml of brine # 2 plus 10 g of the same sand (brine / sand mixture) used in Example 2 was titrated with 1N HCl. The initial pH of the brine / sand mixture was 7.88. Aliquots of 0.1 ml of 1N HCl were added to this mixture repeatedly, and the pH was measured after each addition of HC1. The results shown both in Table 6 and in Figure 4 indicated that the addition of 0.3 milliequivalents of HC1 was necessary to achieve the equivalence point with 10 gr of sand present. The data obtained in this experiment underline the slight capacity of the sand to neutralize the added HC1. Consequently a small concentration of an acid, such as HC1, ionized the amine associated with the sand without having neutralized by reaction with the sand.

TABLE 6 Titration of brine # 2 and 10 gr of sand EXAMPLE 4 REMOVAL OF N, -DIMETHYL-1-DODECA AMINE FROM THE SAND THROUGH IONIZATION AT LOW pH WHICH USES 10% NITRIC ACID The procedure outlined in Example 2 was used to produce the sand / amine mixture except that 519 mg of the amine, 10 g of Pentane and 60,062 gr of sand of the Oa and Ob layers were used. 29,065 gr of this sand / amine mixture was added to 100 mL of # 2 brine (above) to create the sand / amine / brine mixture. The initial pH of the sand / amine / brine mixture was 8.28. The concentration of the amine in the water must have been approximately 2000 ppm if all the amine was dissolved in the # 2 brine. Instead, the analysis of a sample of brine # 2 in contact with the sand / amine / brine mixture as described above showed that the amine concentration was -85 ppm, ie, much less than what was expected. The fact that only a small amount of the amine was detected in brine # 2 underlined the strong bond of the amine to the sand particles. 0.1 ml of 10% by weight nitric acid (% by weight) in water was added to this solution and the pH in the amine concentration was measured again. This step was repeated several times and the results of the values are shown in Table 7 as in Figure 5. The complete ionization and solubilization in the water of the amine was observed at a pH below ~6.7. This is a surprising discovery since the pKa of nitric acid is -1.37 (Langes Handbook of Chemistry, 14th edition, page 8.15, 1992, McGraw-Hill, Inc., New York), the concentration of nitric acid required for this stage in addition it can be reduced several orders of magnitude of 10% by weight used in this experiment without any negative impact on the removal of the amines from the sand.

TABLE 7 Amine concentration measured in Example 4 EXAMPLE 5 REMOVAL OF N, N-DIMETHYL-1-DODECANAMINE FROM THE SAND THROUGH OF IONIZATION AT LOW pH WHICH USE 10% ACETIC ACID The same procedure summarized in Example 4 was repeated here to produce the sand / amine mixture. 30.85 grams (gr) of the sand / amine mixture was added to 100 ml of brine # 2 (above) to create the sand / amine / brine mixture. The initial pH of the sand / amine / brine sample was 8.52. The concentration of the amine in the water should have been approximately 2000 ppm if all the amine was dissolved in the # 2 brine. In contrast, the analysis of brine # 2 in contact with the sand / amine / brine mixture, as described above, showed that the amine concentration was -67 ppm, that is, much less than what was expected. . The fact that only a small amount of the amine was detected in brine # 2 underlined the strong bond of the amine to the sand particles. 0.1 ml of 10% by weight acetic acid was added to this solution and the pH and amine concentration were measured again. This step was repeated several times and the results of analysis are shown in both Table 8 and Figure 6. The complete ionization and solubilization in the water of the amine was observed at pH below ~6.7. This is a surprising discovery since the pKa of acetic acid is 4,756 (Langes Handbook of Chemistry, 14th edition, page 8.19, 1992, McGraw-Hill, Inc., New York). Consequently, the concentration of acetic acid required for this step can also be significantly reduced from what was used in this example without any negative impact on the removal of the amine from the sand.

The observations described above illustrate that a weak organic acid, similar to acetic acid, can be as effective as a strong inorganic acid, similar to hydrochloric acid, in the ionization and separation of amines from toxic sand. Therefore it can be concluded that to remove the toxic zone from an underground site, any acid that lowers the pH of a solution below about 6.7 can be used.

TABLE 8 Amine concentration measured in Example It is noted that in relation to this date, the best method known to the applicant to carry out the aforementioned invention is that which is clear from the present description of the invention.

Claims (16)

CLAIMS Having described the invention as above, the content of the following claims is claimed as property:

1. A method, characterized in that it comprises in order the steps of: a) treating an underground site in an area adjacent to a water injection well with at least one detoxification agent and b) add an inoculum of microorganisms where the microorganisms comprise one or more species of: Co / nanorias, Fusibacter, Marinobacterium, Petrotoga, Shewanella, Pseudomonas, Vibrio, Thauera and Microbulbifer useful in the recovery of improved oil, microbial to the injection well of water; wherein prior to the treatment of (a) at least one corrosion inhibitor and its degradation products, if present, have been adsorbed in the area and have accumulated at concentrations that are toxic to the microorganisms used in the recovery processes of improved petroleum, microbial, in order to form a toxic zone.

2. The method according to claim 1, characterized in that the corrosion inhibitor is an organic compound selected from the group consisting of organic phosphonates, organic nitrogen compounds such as amines, organic acids and their salts and esters, carboxylic acids and their salts and esters, sulfonic acids and their salts, acetylenic alcohols, organic azoles, gluteraldehyde, tetrahydroxymethyl phosphonium sulfate (THPS), acyclolethiocyanate bistiocyanate, docecylguanine hydrochloride, formaldehyde, chlorophenols, organic oxygen scavengers and various nonionic surfactants and combinations thereof.

3. The method in accordance with the claim 2, characterized in that the corrosion inhibitor comprises quaternary ammonium compounds or their degradation products.

4. The method in accordance with the claim 3, characterized in that the quaternary ammonium compound is selected from the group consisting of benzalkonium chloride, bis-quaternary ammonium salts, quaternary nitrogen compounds and imidazoline compounds.

5. The method in accordance with the claim 1, characterized in that the corrosion inhibitor is an inorganic compound selected from the group consisting of chlorine, hypochlorite, bromine, hypobromide, chlorine dioxide, hydrazine, anthraquinone, phosphates, sodium sulfite, salts containing chromium, molybdate or zinc and combinations thereof.

$. The method according to claim 1, characterized in that the detoxification agent of (a) is a dispersing agent.

7. The method in accordance with the claim 6, characterized in that the dispersing agent is an acid selected from the group consisting of hydrochloric acid, nitric acid, hydrochloric acid, acetic acid and oxalic acid.

8. The method in accordance with the claim 6, characterized in that the dispersing agent causes the dissociation of the corrosion inhibitor from the underground site adjacent to the water injection well and disperses it and dilutes it such that the corrosion inhibitor becomes non-toxic to the microorganisms and the underground site adjacent to the well Water injection is detoxified.

9. The method according to claim 1, characterized in that the detoxification agent is a degradation agent.

10. The method in accordance with the claim 9, characterized in that the degradation agent is a strong oxidizing agent selected from the group consisting of nitrates, nitrites, chlorates, perchlorates, chlorites and combinations thereof.

11. The method according to claim 1, characterized in that the detoxification agent is both a dispersing agent and a degradation agent.

12. The method in accordance with the claim II, characterized in that the detoxification agent is hydrogen peroxide or perchlorate.

13. The method according to claim 1, characterized in that the corrosion inhibitor is a growth inhibitor of sulfate-reducing bacteria.

14. The method according to claim 1, characterized in that the microorganisms colonize the detoxified underground site adjacent to the water injection well to perform the recovery of improved, microbial oil.

15. The method according to claim 1, characterized in that the inoculum comprises one or more of Territorial comanonas, Fusibacter paucivorans, Marinobacterium georgiense, Petrotoga miotherma, Shewanella putrefaciens, Pseudomonas stutzeri, Vibrio alginolyticus, Thauera aromatic,, Thauera chlorobenzoica and Microbulbifer hydrolyticus.

16. The method according to claim 15, characterized in that the aromatic Thauera is the ATCC9497 strain, the Pseudomonas stutzeri is the ATCC strain PTA8823 and the Shewanella putrefaciens.es the ATCC strain PTA-8822.