NO20130128A1 - Process for the treatment of underground sites up to water injection wells - Google Patents

Abstract

Procedures for improving the effectiveness of MEOR or bioremediation processes have been provided. In this process, toxic chemicals are accumulated in underground sites until 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

This application claims priority from the following US national patent applications: 12/833,018,12/833,020,12/833,039,12/833,041,12/833,043,12/833,050,12/833,058, and 12/833,070, each filed Jul. 9, 2010 , and each in its entirety incorporated herein by reference.

FIELD OF THE INVENTION

The invention relates to the area of microbial enhanced oil recovery and bioremediation of contaminated underground sites. In particular, it relates to methods for treating the toxic chemicals accumulated in underground locations up to the water injection wells before the introduction of microbial inocula for microbial enhanced oil recovery or bioremediation of these locations.

BACKGROUND OF THE INVENTION

Traditional oil recovery techniques that use only the natural forces present at an oil well site allow recovery of only a minor portion of the crude oil present in an oil reservoir. Oil well sites generally refer to any location where wells have been drilled into a bedrock containing oil with the intention of producing oil from that bedrock. An oil reservoir typically refers to a deposit of underground oil. Additional extraction methods such as waterflooding have been used to push oil through the underground site towards the production well and thus improve the recovery of crude oil (Hyne, N.J., 2001, "Non-technical guide to petroleum geology, exploration, drilling, and production", 2nd edition, Pen Well Corp., Tulsa, OK, USA).

To meet the increasing global demand for energy, there is a need to further increase the production of crude oil from oil reservoirs. A further supplementary technique used for enhanced oil recovery from oil reservoirs is known as Microbial Enhanced Oil Recovery (MEOR) as described in U.S. Pat. Pat. No. 7,484,560. MEOR, which has the potential to be a cost-effective way to increase oil recovery, involves either stimulating natural oil reservoir microorganisms or injecting specifically selected microorganisms into the oil reservoir to produce metabolic effects that lead to increased oil recovery.

The production of oil and gas from underground oil reservoirs requires the installation of various equipment and pipelines on surfaces or in the underground locations of the oil reservoir that come into contact with corrosive fluids in gas and oil field applications. Oil recovery is thus simplified by preserving the integrity of the equipment necessary to provide water to water injection wells and bring oil and water from the production wells. As a result, corrosion can be a significant problem in the petroleum industry due to the cost and downtime associated with replacing corroded equipment.

Sulfate-reducing bacteria (SRB), which produce hydrogen sulfide (H2S), are among the main contributors to the corrosion of ferrous metal residues and oil recovery equipment. These microorganisms can cause acidification, corrosion and plugging and thus have a negative influence on a MEOR or a bioremediation process. Bioremediation refers to processes that use microorganisms to clean up oil spills or other contaminants from either the surface or subsurface locations of soil.

To combat corrosion, corrosion inhibitors, which are chemicals or agents that lower the corrosion rate of metal or an alloy and are often toxic to microorganisms, are used to preserve the water injection and oil recovery equipment in such wells. In practice according to the present invention, a water injection well is a well through which water is pumped into an oil-producing reservoir for pressure maintenance, heat transfer, or increased oil recovery. The important 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).

US patent application with publication no. 2006/0013798 describes using bis-quaternary ammonium salts as corrosion inhibitors to preserve metal surpluses in contact with fluids to extend the life of these assets.

US patent no. 6,984,610 describes methods for cleaning up oil mud and drilling mud residues from well cuttings, surface oil drilling and production equipment using acids, pressure fracturing, and acid-based micro-emulation for increased oil recovery.

WO2008/070990 describes the pretreatment of oil wells using pretreatment agents such as methyl ethyl ketone, methyl propyl ketone and methyl tert-butyl ether in the injection water to improve oil recovery. Mechanisms such as modifying the viscosity of the oil in the reservoir and reviving the heavy oil were attributed to this process.

US2009/0071653 describes the use of surfactants, etchants, anti-caking agents and abrasives to prevent or remove the build-up of fluid films on process equipment to increase the well's capacity.

Studies indicate that the long-term addition of chemicals or agents used to control undesirable events such as corrosion, scale, microbial activities and foaming in the water supply to a water injection well does not lead to their accumulation in high enough concentrations to adversely affect the microorganisms used in the MEOR ( Carolet, J-L. 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 MEOR or bioremediation processes is a concern. It may be desirable to modify MEOR or bioremediation treatments so that the viability of the microorganisms used is maintained throughout these processes so that MEOR or bioremediation processes become more efficient.

SUMMARY OF THE INVENTION

The present description relates to a method for improving the efficiency of a MEOR or bioremediation process by detoxifying underground locations adjacent to oil wells, in which the wells have previously been treated with corrosion inhibitors prior to inoculation of the microorganisms required for MEOR or bioremediation.

In one aspect, the present invention is a method comprising in sequence the steps of: a) treating an underground site in a zone adjacent to a water injection well with a detoxifying agent; and b) adding an inoculum of microorganisms in which the microorganisms comprise one or more species of: Comamonas, Fusibacter, Marinobacterium,

Petrotoga, Shewanella, Pseudomonas, Vibrio, Thauera and Microbulbifer useful in microbial enhanced oil recovery for the water injection well;

wherein prior to the treatment in (a) at least one corrosion inhibitor and its degradation products if present have been adsorbed into the zone and have accumulated to concentrations toxic to microorganisms used in microbially enhanced oil recovery processes, thereby forming a toxic zone.

BRIEF DESCRIPTION OF THE FIGURES

Figure 1 is a schematic representation of a water injection well and

the underground locations up to the water injection well. 1 is the flow of injection water into the well casing 7, 2 and 3 are bedrock, 5 are perforations in the casing, 4 are fractures in the bedrock. 6 is the surface of the rock formation made by the borehole, 7 is the well casing. 8 is one side of the wet zone that is axially symmetrical with the injection well, shown by a dashed box in rock layer 3.

Figure 2 is a 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 confining the thin tube; 10 and 11 are the opposite ends of the pressurized container; 13 is a pump; 14 is the supply reservoir; 15 is the water inlet for the pressure vessel; 16 is the back pressure regulator; 17 is the high-pressure air supply; 18 is an inlet fitting connecting the thin tube inside the pressure vessel to the pump and pressure transducers; 21 is an outlet fitting connecting the thin tube inside the pressure vessel to the back pressure regulator and the low side of the differential pressure transmitter; 19 is a differential pressure transmitter; and 20 is an absolute pressure transmitter. Figure 3 shows the titration of amine-coated sand; ♦er represents amine in solution from amine-coated sand and Der represents the first derivative of the titration curve (the central differences). Figure 4 shows the titration of salt solution and sand with IN HC1; Here represents the pH of the salt solution #1 with 10 grams of sand; ^er represents the pH of only salt solution #1; Ser represents the slope of pH of salt solution #1 with 10 grams of sand; and Aer represents the slope of the pH of just salt solution #1. Figure 5 shows the titration of salt solution and sand contaminated with amine with 10% nitric acid; ^er represents the concentration of amine observed in solution for a given pH. Figure 6 shows the titration of salt solution and core sand with 10% acetic acid; ^er represents 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 of detoxifying the corrosion inhibitors and their degradation products, if present, which have accumulated in a subsurface site adjacent to a water injection well in an oil well site. The applicants have found that oil recovery process aids such as corrosion inhibitors can accumulate in the area next to the water injection well and build up to concentrations that are toxic to microorganisms used in MEOR or bioremediation. As the term is used herein, to "detoxify" or "detoxify" a water injection site means to remove or reduce the toxicity caused by corrosion inhibitors and their breakdown products to microorganisms to allow their growth and activity of said microorganisms, used in MEOR or bioremediation.

For the purposes of the present invention, the term "toxic zone" refers to an underground location next to the water injection well containing toxic concentrations of agents such as corrosion inhibitors or their degradation products that have adverse effects on the growth and metabolic activities of microorganisms used in MEOR and/or bioremediation. These agents can bind to sand, rock, clay in the rock and/or oil that is bound to the rock and create a toxic zone. A toxic agent, as the term is used herein, is any chemical or biological agent that negatively affects the growth and metabolic functions of the microorganisms used in MEOR or bioremediation.

Figure 1 is a schematic representation of an underground location next to a water injection well. The injection water 1 flows into the well casing pipe 7 which is inside the borehole 6 drilled through the rock layer (2 and 3). There is an opening between the well casing pipe 7 and the side surface 6 of the rock layer made by the borehole 5. Rock layer 2 represents impermeable rock above and below a permeable rock 3 that holds or traps the oil. The injection water 1 flows down the well casing and passes through perforations 5 in the casing 7 and into fractures 4 in the permeable rock 3. This injection water then flows through the permeable rock layer 3 and moves oil from a wet zone 8 to the borehole. This zone extends radially out from the borehole 6 in all directions in the permeable rock layer 3. The volume of the permeable rock 3 encompassed by the dashed line 8 is illustrated only on one side of the borehole, but it actually exists on all sides of the borehole. This wet zone represents the underground location next to the water injection well.

Corrosion inhibitors, together with their degradation products if present, which can accumulate to levels toxic to microorganisms used in MEOR are, for example, inorganic corrosion inhibitors such as chlorine, hypochlorite, bromine, hypobromide and chlorine dioxide. Additional potential toxic accumulative 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, C. U., et al., Appl. Environ. Microbiol., 74: 2841-2851, 2008).

Organic compounds used as corrosion inhibitors that can accumulate and form a toxic zone include: acetylene alcohols, organic azoles, gluteraldehyde, tetrahydroxymethylphosphonic sulfate (THPS), bisthiocyanatacrolein, dodecylguanine hydrochloride, formaldehyde, chlorophenols, organic oxygen scavengers and various nonionic surfactants.

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

Applicants have determined that corrosion inhibitors can accumulate by adsorption into or at the subsurface site (eg, rock, clay, sandstone, unconsolidated sand, or limestone) or into the oil that has been trapped in the oil reservoir subsurface site. Long-term addition of these chemicals results in their accumulation and the formation of a toxic zone in the underground locations next to the water well with adverse effects on microbial inocula intended for MEOR and/or bioremediation applications.

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 pipe can be set up and packed with cored sand from an oil well site. The model system as described herein can be set up using pipes, valves and fittings compatible with the crude oil or the hydraulic solution used which can withstand the range of applied pressure during the process. An absolute pressure transmitter, differential pressure transmitter, and back pressure regulator, for example manufactured by Cole Plamer (Vernon Hill, IL) and Serta (Boxborough, Mass.), are used in the model system and are commercially available. The toxic zone model can be established by applying solutions of amines and/or amine mixtures and flushing them through a pipe packed with core sand from an oil reservoir. Other corrosion inhibitors suitable for use in constructing a model may include organic phosphonates or anthraquinone or phosphates. The concentration of the corrosion inhibitors used to create the toxic zone model can be from 0.01 to 10 parts per million.

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

Treating a toxic zone in a subsurface site up to a water injection well with a detoxifying agent is accomplished by any method of introducing a chemical into a subsurface site well known to those skilled in the art. Typically, treatment is by introducing a composition containing a detoxifying agent into the well as shown in the diagram in Figure 1 for injection water 1. The detoxifying agent composition flows through the well casing 7, through perforations 5, and into fractures 4 in the permeable rock layer 3 in the wet zone 8. This is the zone next to the water injection well where a toxic zone can be formed and treated with a detoxifying agent.

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

Detoxification of the chemicals accumulated in a toxic zone can also be achieved by using a dispersant. A dispersant as the term is used herein includes any chemical that causes absorbed toxicants to be removed from the reservoir rock and/or sand in a toxic zone and dissolves them in water during waterflooding thereby allowing natural dispersion and diffusion to lower the concentration where it no longer is toxic to MEOR or bioremediation microorganisms.

In one embodiment, a dispersant includes any chemical that lowers the pH of a solution, ionizes amines and dissolves them in water during waterflooding and allows natural dispersion and diffusion to lower the concentration where it is no longer toxic to MEOR or bioremediation microorganisms. For example, amines are quite unreactive under mild conditions, however, they become ionized at lower pH. The treatment of the amines with an acid thus increases their solubility and frees them from oil and/or from rock and disperses them from the toxic zone. The dissolved amines can therefore move into the water flowing through the well. A combination of radial flow, dispersion and desorption can allow the dissolved amines to be diluted and dispersed over a large area (from at least 10 to about 200 feet (from at least 3 meters to about 7 meters)) of the oil well. Consequently, subsequent dilution and dispersion of the amines over a much larger area would have reduced their concentrations within the subsurface location of the well to non-toxic levels for MEOR or bioremediation microorganisms. In another embodiment, hydrogen peroxide may be added to the toxic zone, as both a disintegrant and a dispersant, from about 1,000 parts per million to 70,000 parts per million by volume of water. In another embodiment, perchlorates may be added, as both a disintegrant and a dispersant, from about 1 part per million to about 10,000 parts per million.

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

In a MEOR process, an inoculum of viable microorganisms is added to the water that is injected into the water injection well (see Figure 1). The term "inoculum of microorganisms" refers to a composition containing viable microorganisms. These microorganisms colonize, i.e. grow and reproduce, in underground locations close to the water injection well to increase the MEOR. The recovery of oil can be increased by effects of the microorganisms such as releasing oil from underground rock and/or sand, and forming plugging biofilms that will increase the sweep efficiency in waterflooding secondary oil recovery.

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

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

An inoculum of microorganisms is added to an underground location by any method for microorganism introduction that is well known to the person skilled in the art. Typically, inoculum is added to the water injection well as part of injection water 1 which is introduced into the well casing 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 species: 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 Comamonas terrigena, Fusibacter paucivorans, Marinobacterium georgiense, Petrotoga miotherma, Shewanella putrefaciens, Pseudomonas stutzeri, Vibrio alginolyticus, Thauera aromatica. Thauera chlorobenzoica and Microbulbifer hydrolyticus.

In one embodiment, an inoculum of Shewanella putrefaciens LH4:18 (ATCC PTA-8822), described in US 7,776,795, can be used in the present method. In another embodiment, Pseudomonas stutzeri LH4:15 (ATCC PTA8823), described in US patent application publication no. US20090263887, with the same owner and which is pending at the same time

with the present application, is used in the present method. In another embodiment, Thauera aromatica AL9:8 (ATCC 9497), described in US patent application with

publication no. US20100078162, with the same owner and which is being processed at the same time as the present application, is used in the present method.

EXAMPLES

The present invention is further defined in the following examples. It should be understood that these examples, which indicate 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 determine the essential characteristics of this invention, and make various changes and modifications to the invention to adapt it to different applications and conditions.

GENERAL METHODS:

Chemicals and materials

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

Amino acids

The concentration of amines, in media and water, was analyzed by gas chromatography (GC). An Agilent Model 5890 (Agilent, Wilmington, DE), GC equipped with a flame photoionization detector and a split/splitless injector, a DB-FFAP column (30 meter length x 0.32 millimeter (mm) depth x 0.25 micrometer particle size). The equipment had an Agilent ALS Autoinjector, 6890 Model series with a 10 milliliter (ml) syringe. The system was calibrated using a sample of N,N-dimethyl-1-dodecanamine (Aldrich). Helium was used as carrier gas. A temperature gradient of 50 degrees Celsius (°C) to 250°C at 30°C increments per minute (min) was used. Retention times (in minutes, min) for various chemicals of interest include: N,N-dimethyl-l-dodecanamine (8.08 min); N,N-dimethyl-1-tetradecanamine (8.85 min); N,N-dimethyl-1-hexadecane-amine (9.90 min); N,N-dimethyl-1-octadecanamine

(10.26 min) and N-methyl,N-benzyl-1-tetradecanamine (11.40 min).

EXAMPLE 1

ESTABLISHMENT OF A TOXIC ZONE IN OIL WELL SAND USING A MIXTURE OF AMINES IN A MODEL SYSTEM

A sample of the sand from the Schrader Bluff Formation at the Milne Point 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 then drained and evaporated from the sand to give clean, dry, flowable sand. The sand was screened to remove particles less than one micrometer in size and was then tightly packed into a four foot (121.92 cm) long flexible thin tube 9 and compacted by vibration using a laboratory excavator. Both ends of the thin tubes were capped to keep the sand inside. The complete apparatus is shown in Figure 2. Tubes capable of withstanding the amount of pressure used in the thin tube were connected to the end caps. The thin pipe 9 was fitted into the pressure vessel 10 with pipes passing through the ends 11 and 12 of the pressure vessel using pressure fittings 18 and 21. Further fittings and pipes were used to connect the inlet of the thin pipe 11 to a pressure pump 13 and a supply reservoir. .

Additional fittings and pipes connected the inlet of the thin pipe to an absolute pressure transmitter 20 and the high pressure side of a differential pressure transmitter 19. Fittings and pipes connected the outlet of the thin pipe 12 to the low pressure side of a differential pressure transmitter 19 and to a back pressure regulator 16. The signals from differential pressure transmitter 1 and the absolute pressure transmitter were loaded into a computer and the pressure reading was monitored and periodically recorded. The pressure vessel 10 surrounding the thin tube was filled with water through a water port 15. This water was then slowly pressurized with air 17 to a pressure of approximately 105 psi (per sqaure inch) (0.72 megaPascal) while brine #1 from the supply reservoir 14 ( Table 1) flowed through the thin pipe and exited the thin pipe through the back pressure regulator 16. This operation was performed so that the pressure in the thin pipe was always 5 to 20 psi (0.034 - 0.137 megaPascal) below the pressure in the pressure vessel 10.

Acetate 0.2 gr (200 ppm acetate)

The pH of saline solution #1 was adjusted to 7.0 with either HCl or NaOH and the solution was filter sterilized.

When the pressure inside and outside the thinned pipe was established, one pore volume of the crude oil from the oil reservoir from the Milne Point Unit in the Alaska North Slope was pumped into the thinned pipe. This process was carried out for several hours (t). When the crude oil had saturated the sand in the thinned pipe and was observed in the effluent, the flow was stopped and the oil was allowed to age in the core sand for three weeks. At the end of this time, saline solution #1 was pumped through the thinned tube at a rate of ~1.5-3.5 milliliters per hour (ml/h) (~1 pore volume every 201). Samples were taken from the effluent and the concentration of natural microflora in them was determined.

After 51 pore volumes of flow through the thin tube, the concentration of native microflora in the system was approximately 1x10<7>colony forming units per milliliter (CFU/ml). At this point, a mixture of amines (hereafter amines/salt solution mixture) was added at 150 ppm concentration to salt solution #1. The approximate composition of the mixture of amines (Table 2) consisted of 7 different amine components that were identified. Five were identified by mass spectrometry (Agilent Technologies, Inc. Santa Clara, CA) as N-N-dimethyl-l-dodecanamine, N-N-dimethyl-l-tetradecane-amine, N-N-dimethyl-methane-thioamide, caprolactam, and N-methyl-N -benzyl-1-tetradecanamine. Two of these components were identified as amines, but specific chemical formulas could not be determined for them because mass spectral fragmentation patterns could not be deciphered. These are marked in Table 2 as "minor amine" and "other amine". Analysis of the effluent from the thin tube did not indicate the presence of any amines. The experiment was continued by pumping 150 ppm of the mixture of amines in brine #1 through the thin tube.

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

After 80 pore volumes of the mixture of brine #1 with 150 ppm of the mixture of amines were pumped into the thin tube, a total of about 1 gram of the mixture of amines had flowed through the thin tube. At this point, 80 ppm of amines were finally observed in the effluent in the thin tube. This very long delay in seeing the amines in the effluent means that virtually all of the amines had been trapped in the thin tube. Additionally, no natural microflora could be seen in the effluent at this time, indicating that the thin tube had become toxic enough to kill any existing microflora. At this point, pumping of the amine-free brine #1 began in an attempt to flush the amines out of the thin tube and make it less toxic.

After 24 pore volumes of the amine-free salt solution #1 had been pumped through the thin tube, 51 ppm amines were detected in the effluent. The thin tube was then inoculated with one pore volume of Shewanella putrefaciens (ATCC PTA-8822) at a concentration of approximately 1x10<9>CFU/ml. The inoculum was not allowed to remain in the thin tube. Instead, the amine-free salt solution #1 was flushed through the thin tube immediately after inoculation. Consequently, the microbes remained in the thin tube for only a few hours during the passage through it. It was therefore expected that the concentration of the micro-organisms in the effluent could be measured in the effluent leaving the thin tube. Remarkably, however, no microorganisms (representing approximately a 9 log kill) were detected in the effluent in the thin tube despite the short residence time of the inoculum in the thin tube. This experiment confirmed that a toxic zone had been established in the thin tube. In a sustained attempt to detoxify the thin tube, saline solution #1 alone was continuously pumped through it.

After 79 pore volumes of the amine-free salt solution #1 had been pumped through the thin tube, the amine concentration in the effluent in the thin tube was measured at 30 ppm. The thin tube was inoculated with another pore volume of Shewanella putrefaciens (at lx10<9>CFU/ml). The CFU/ml in an effluent sample was about 1x10<4> and showed that more than a 5 log kill of this microorganism had occurred immediately after inoculation. This experiment emphasized the persistent toxic effect of the amines despite extensive washing of the tube with the amine-free saline #1 solution.

After 108 pore volumes of the amine-free salt solution #1 had been pumped through the thin tube, the amine concentration in the effluent was measured at 5 ppm. The thin tube was inoculated with an additional pore volume of Shewanella putrefaciens containing lx109 CFU/ml. CFU/ml in the effluent sample of the thin tube immediately after inoculation indicated a 4-5 log kill of this microorganism despite the extensive washing with the amine-free saline solution #1 and the decrease in the amine concentration in the effluent. These results further confirmed the persistent toxic effect of the mixture of amines accumulated in the thin tube.

After 143 pore volumes of the amine-free salt solution #1 had been pumped through the thin tube, one pore volume of an inexpensive, odorless white spirit (OMS) (Parks OMS, Zinsser Co., Inc., Somerset Jew Jersey #2035 CAS #8052- 41-3) pumped through the thin tube in an attempt to remove the remaining mixture of amines. After this rinse with OMS, pumping of amine-free salt solution #1 continued through the thin tube.

After 149 pore volumes of the amine-free salt solution #1 had been pumped through the thin tube, the amine concentration in the effluent was measured at 4 ppm and the thin tube was inoculated with an additional pore volume of Shewanella putrefaciens (lxlO<9>CFU/ml). A count of microorganisms in the sample of the thin tube effluent showed a 2 - 3 log kill (99 to 99.9%) despite the OMS rinse and the extensive washing with the amine free saline solution #1. These results confirmed that the toxic zone in the thin tube still killed virtually all of the microorganisms added to the tube.

After 168 pore volumes of the amine-free salt solution #1 had been pumped through the thin tube, one pore volume of a solution of 10% HCl in water was pumped through the thin tube to remove amines. After this acid wash, the amine-free salt solution #1 was continuously pumped through the thin tube.

After the acid wash treatment, an additional 2 pore volumes of the amine-free salt solution #1 was pumped through the thin tube and the amine concentration in the effluent was measured at 0.5 ppm. The thin tube was then inoculated with an additional pore volume of Shewanella putrefaciens (lx10<9>CFU/ml). CFU/ml in the effluent showed approximately a 0.4 log kill of this microorganism. These results emphasized the survival of several microorganisms following acid washing of the thin tube and the effectiveness of using an acid to detoxify the toxic zone of the thin tube. Table 3 below summarizes the results of the various tests described above.

EXAMPLE 2

REMOVAL OF N N-DIMETHYL-1-DODECANAMINE FROM SAND BY THEIR IONIZATION AT LOW PH USING HYDROCHLORIC ACID 38 milligrams (mg) of N N-dimethyl-l-dodecanamine (hereafter referred to as "the amine") was added to 10.210 grams pentane. This solution was added to 10.1845 grams of specific sand layers (Oa and Ob) obtained from the Schrader Bluff Formation in the Milne Point Unit of the Alaska North Slope.

The oil content of the sand was first removed by using a mixture of methanol and toluene (50/50, volume/volume) as solvent washes. The solvent mixture was then evaporated off the sand to give clean, dry, flowable sand. This sand was mixed with the amine and pentane solution to give a slurry. This slurry was thoroughly mixed and pentane was evaporated off while amine remained on the sand (hereafter referred to as sand/amine mixture). 100 mL of saline solution #2 (recipe below) was added to the sandVamin mixture to form the sand/amine/saline mixture. The initial pH of the sand/amine/salt solution mixture was 8.4. The concentration of the amine in the water would have been 380 ppm if all the amine was dissolved in salt solution #2. Analysis of the sample of the sand/amine/salt solution mixture by GC did not reveal the presence of any amines in the test sample (ie, the amine concentration was ~<1 ppm). The fact that the amine was not detected emphasized its strong binding to the sand particles. 0.1 ml of 1 normal (N) HCl was added to this solution and the pH and amine concentration were measured again. This step was repeated several times and the analysis results are shown in both Table 4 and Figure 3. Complete ionization and dissolution of the amine in the water was observed at pH below ~6.0. This is a surprising finding since the pKa of HC1 is -6.2 (Lange's Handbook of Chemistry, 14* edition, page 8.14, 1992, McGraw-Hill, Inc., New York). The concentration of HCl required for this step to completely ionize the amine and remove it from the toxic sand can therefore be further reduced by several orders of magnitude from the 10% concentration used in this example. The data emphasize the remarkable effectiveness of an acid in ionizing and removing the amine from the sand. ; EXAMPLE 3 ;THE CAPACITY OF SAND TO NEUTRALIZE ACID ;A. Titration of Salt Solution #2 in the Absence of Sand ;The purpose of this experiment was to determine the capacity of sand described in Example 2 to neutralize HC1 intended to ionize the amine accumulated in the sand. ;To establish a control test, 100 mL of saline #2 was titrated with 1 N HCl to an initial pH of 8.1. An aliquot (0.1 mL) of 1 N HCl was added to the #2 salt solution and the pH was measured. The HCl addition was repeated several times and the pH was measured after each addition. Results of these analyzes are shown in both Table 5 and Figure 4. The data indicated that approximately 2.25 milliequivalents of HC1 were required to achieve the equivalence point of approximately pH 4 corresponding to approximately 100% recovery of the carbonate present in brine #2. ; B. Titration of salt solution #2 with sand; 100 ml of salt solution #2 plus 10 grams of the same sand (salt solution/sand mixture) used in example 2 was titrated with 1N HCl. The starting pH of the salt solution/sand mixture was 7.88. 0.1 mL aliquots of 1N HCl were repeatedly added to this mixture, and the pH was measured after each HCl addition. The results shown in both 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 grams of sand present. The data obtained in this experiment emphasize the small capacity of sand to neutralize the added HC1. Consequently, a low concentration of an acid, such as HCl, ionizes the amine associated with the sand without being neutralized by reaction with the sand. ; ; EXAMPLE 4 ;REMOVAL OF N- N-DIMETHYL- 1 -DODECANAMINE FROM SAND BY THEIR ;IONIZATION AT LOW pH USING 10% NITRIC ACID ;The procedure described in Example 2 was used to prepare the sand/amine mixture except that 519 mg of the amine, 10 grams of pentane and 60.062 grams of sand from the Oa and Ob layers were used. 29.065 grams of this sand/amine mixture was added to 100 ml of brine #2 (above) to form the sand/amine/salt mixture. The initial pH of the sand/amine/salt solution mixture was 8.28. The concentration of the amine in the water should have been about 2000 ppm if all the amine had been dissolved in saline solution #2.1 instead, analysis of a sample with saline solution #2 in contact with the sand/amine/saline mixture as described above showed that the amine concentration was ~85 ppm, i.e. much less than expected. The fact that only a small amount of the amine was detected in salt solution #2 emphasized the strong binding of the amine to the sand particles. 0.1 ml of 10 weight percent (wt%) nitric acid in water was added to this solution, and the pH and amine concentration were again measured. This step was repeated several times and the analysis results are shown in both Table 7 and Figure 5. Complete ionization and dissolution of the amine in the water was observed at pH below ~6.7. This is a surprising finding since the pKa of nitric acid is -1.37 (Lange's Handbook of Chemistry, 14* edition, page 8.15,1992, McGraw-Hill, Inc., New York), the concentration of nitric acid required for this step can be further reduced by several orders of magnitude from the 10% by weight used in this example without any negative influence on the removal of the amines from the sand.

EXAMPLE 5

REMOVAL OF N- N- DIMETHYL- 1 - DODECANAMINE FROM SAND BY ITS IONIZATION AT LOW PH USING 10% ACETIC ACID

The same procedure as described in Example 4 was repeated here to prepare the sand/amine mixture. 30.85 grams (gr) of the sand/amine mixture was added to 100 ml of saline solution #2 (above) to form the sand/amine/salt solution mixture. The initial pH of the sand/amine/salt solution mixture was 8.52. The concentration of the amine in the water should have been approximately 2000 ppm if all the amine had been dissolved in salt solution #2.1 instead, analysis of salt solution #2 in contact with the sand/amine/salt solution mixture, as described above, showed that the amine concentration was ~67 ppm, i.e. .much less than expected. The fact that only a small amount of the amine was detected in salt solution #2 emphasized the strong binding 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 again measured. This step was repeated several times and the analysis results are shown in both Table 8 and Figure 6. Complete ionization and dissolution of the amine in the water was observed at pH below ~6.7. This is a surprising finding since the pKa of acetic acid is 4.756 (Lange's Handbook of Chemistry, 14th edition, page 8.19, 1992, McGraw-Hill, Inc., New York). Accordingly, the concentration of acetic acid required for this step can be further significantly reduced compared to that used in this example without any negative influence on the removal of the amines from the sand.

The observations described above illustrate that a weak organic acid, such as acetic acid, can be as effective as a strong inorganic acid, such as hydrochloric acid, in ionizing and separating the amines from the toxic sand. It can therefore 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.

Claims (16)

1. Method comprising in sequence the steps of: a) treating an underground site in a zone adjacent to a water injection well with at least one detoxifying agent; and b) adding an inoculum of microorganisms wherein the microorganisms comprise one or more species of: Comamonas, Fusibacter, Marinobacterium, Petrotoga, Shewanella, Pseudomonas, Vibrio, Thauera and Microbulbifer useful in microbial enhanced oil recovery to the water injection well; wherein prior to the treatment in (a) at least one corrosion inhibitor and its degradation products if present have been adsorbed into the zone and have accumulated to concentrations toxic to microorganisms used in microbially enhanced oil recovery processes, thereby forming a toxic zone. 2. Method according to claim 1, in which 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, sulphonic acids and their salts, acetylene alcohols, organic azoles, gluteraldehyde, tetrahydroxymethylphosphomum sulfate (THPS), bisthiocyanatacrolein, dodecylguanine hydrochloride, formaldehyde, chlorophenols, organic oxygen scavengers and various nonionic surfactants and combinations thereof. 3. Method according to claim 2, in which the corrosion inhibitor comprises quaternary ammonium compounds or their decomposition products. 4. Method according to claim 3, in which the quaternary ammonium compound is selected from the group consisting of benzalkonium chloride, bis-quaternary ammonium salts, quaternary nitrogen compounds and imidazoline compounds. 5. Method according to claim 1, wherein the corrosion inhibitor is an inorganic compound selected from the group consisting of chlorine, hypochlorite, bromine, hypobromide, chlorine dioxide, hydrazine, anthraquinone, phosphates, sodium sulphite, salts containing chromium, molybdate or zinc, and combinations thereof. 6. Method according to claim 1, in which the detoxifying agent from (a) is a dispersant. 7. Method according to claim 6, in which the dispersant is an acid selected from the group consisting of hydrochloric acid, nitric acid, hydrofluoric acid, acetic acid and oxalic acid. 8. Method according to claim 6, in which the dispersant causes separation of the corrosion inhibitor from the underground site until the water injection well and disperses and dilutes it so that the corrosion inhibitor becomes non-toxic to the microorganisms and the underground site until the water injection well is detoxified. 9. Method according to claim 1, in which the detoxifying agent is a decomposing agent. 10. Method according to claim 9, wherein the decomposing agent is a strong oxidizing agent selected from the group consisting of nitrates, nitrites, chlorates, perchlorates, chlorites and combinations thereof. 11. Method according to claim 1, in which the detoxifying agent is both a dispersant and a disintegrant. 12. Method according to claim 11, in which the detoxifying agent is hydrogen peroxide or perchlorate. 13. Method according to claim 1, in which the corrosion inhibitor is a growth inhibitor of sulfate-reducing bacteria. 14. Method according to claim 1, in which the microorganisms colonize the detoxified underground site adjacent to the water injection well to perform microbial enhanced oil recovery. 15. Method according to claim 1, wherein the inoculum comprises one or more of Comamonas terrigena, Fusibacter paucivorans, Marinobacterium georgiense, Peirotoga miotherma, Shewanella putrefaciens, Pseudomonas stutzeri, Vibrio alginolyticus, Thauera aromaiica, Thauera chlorobenzoica and Microbulbifer hydrolytieus. 16. The method of claim 15, wherein Thauera aromatica is strain ATCC9497, Pseudomonas stutzeri is strain ATCC PTA8823, and Shewanella putrefaciens is strain ATCC PTA-8822.