WO2012006483A2

WO2012006483A2 - A method for pre-treatment of subterranean sites adjacent to water injection wells

Info

Publication number: WO2012006483A2
Application number: PCT/US2011/043280
Authority: WO
Inventors: Albert W. Alsop; Robert D. Fallon; Scott Christopher Jackson
Original assignee: E. I. Du Pont De Nemours And Company
Priority date: 2010-07-09
Filing date: 2011-07-08
Publication date: 2012-01-12
Also published as: WO2012006483A3

Abstract

A method to improve the effectiveness of a MEOR process has been disclosed. In this method pacifying agents are used to pretreat subterranean sites adjacent to water injection wells such that subsequent treatment with anti-corrosion chemicals would not lead to their accumulation and creation of toxic zones these sites.

Description

A METHOD FOR PRE-TREATMENT OF SUBTERRANEAN SITES

ADJACENT TO WATER INJECTION WELLS

This application claims the benefit of United States Provisional

Applications 61/362,813 and 61/362,719 each filed July 9, 2010 and each incorporated by reference in their entirety.

FIELD OF THE INVENTION

The invention relates to the field of microbial enhanced oil recovery at subterranean sites. Specifically, it relates to methods for pretreatment at water injection wells to reduce or eliminate the accumulation of toxic chemicals that are added to injection water, that otherwise would accumulate in subterranean sites adjacent to the water injection wells, prior to introduction of microbial inocula for microbial enhanced oil recovery at these sites.

BACKGROUND OF THE INVENTION

Traditional oil recovery techniques, which utilize 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 site generally refers to any location where wells have been drilled into a subterranean rock containing oil with the intent to produce oil from that subterranean rock. An oil reservoir typically refers to a deposit of subterranean oil. Supplemental recovery methods such as water flooding have been used to force oil through a subterranean site toward a production well and thus improve 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 rising global demand on energy, there is a need to further increase production of crude oil from oil reservoirs. An additional

supplemental technique used for enhancing oil recovery from oil reservoirs is known as Microbial Enhanced Oil Recovery (MEOR) as described in US 7,484,560. MEOR, which has the potential to be a cost-effective method for enhanced oil recovery, involves either stimulating indigenous oil reservoir microorganisms or injecting specifically selected microorganisms into the oil reservoir to produce metabolic effects that lead to improved oil recovery. The production of oil and gas from subterranean oil reservoirs requires installing various equipment and pipelines on the surface or at subterranean sites of the oil reservoir, which come in contact with corrosive fluids in gas- and oil-field applications. As a result, corrosion can be a significant problem in the petroleum industry because of the cost and downtime associated with replacement of corroded equipment. Thus oil recovery is facilitated by preserving the integrity of the equipment needed to provide water for water injection wells and to convey oil and water from the production wells.

Sulfate reducing bacteria (SRB), which produce hydrogen sulfide (H₂S), are among the major contributors to corrosion of ferrous metal surfaces and oil recovery equipment. These microorganisms can cause souring, corrosion and plugging, and thus can have negative impacts on a MEOR process. To combat corrosion, corrosion inhibitors which are chemicals or agents that decrease the corrosion rate of a metal or an alloy and are often toxic to microorganisms, are used to preserve water injection and oil recovery equipment. The significant classes of corrosion inhibitors include inorganic and organic corrosion inhibitors such as, organic phosphonates, organic nitrogen compounds, organic acids and their salts and esters (Chang, R. J. et al., Corrosion Inhibitors, 2006, Specialty Chemicals, SRI Consulting).

US2006/0013798 describes using bis-quaternary ammonium salts as corrosion inhibitors to preserve metal surfaces in contact with fluids to extend the life of these capital assets.

US 6,984,610 describes methods to clean up oil sludge and drilling mud residues from well cuttings, surface oil well drilling and production equipment through application of acids, pressure fracturing, and acid-based microemulation for enhanced oil recovery.

WO2008/070990 describes preconditioning of oil wells using

preconditioning 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 modifying the viscosity of the oil in the reservoir and enlivening the heavy oil were attributed to this method.

US2009/0071653 describes using a composition containing

surfactants, caustic agents, anti-caking agents and abrasive agents to prevent or remove the build-up of fluid films on processing equipment and geological formations to increase a well's capacity.

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

However, viability of microorganisms used in MEOR or bioremediation processes is a concern. There remains a need for methods of using MEOR that support the viability of microorganisms used throughout the process, thus making them more effective.

SUMMARY OF THE INVENTION

The present disclosure relates to a method for treating an oil reservoir when a microbial enhanced oil recovery (MEOR) process is used, where a pacifying agent is introduced prior to introducing microbes.

Accordingly, the invention provides a method for treating an oil reservoir comprising:

a) providing a subterranean site adjacent to a water injection well in an oil reservoir;

b) contacting the subterranean site with a pacifying agent;

c) contacting the subterranean site with at least one corrosion inhibitor; and

d) contacting the subterranean site with a microbial inoculum

containing at least one strain of microorganism,

wherein the steps are performed in the listed order

BRIEF DESCRIPTION OF THE FIGURES

Figure 1 is the schematic representation of a water injection well and the subterranean sites adjacent to the water injection well. (1 ) is the flow of injection water into the well casing (7), (2 and 3) are rock layers, (4) is perforations in the well casing, (5) is the well bore, (6) is the face of the rock layer made by the well bore, (7) is the well casing, (8) is one side of the watered zone that is axi-symmetric with the injection well, shown by a dotted box in the rock layer (3).

Figure 2 is the schematic of a model system used to simulate formation of a toxic zone. (9) is a long slim tube; (10) is a pressure vessel to constrain the slim tube; (11 and 12) are the opposite ends of the pressurized vessel; (13) is a pump; (14) is a feed reservoir; (15) is a water inlet for the pressure vessel; (16) is a back pressure regulator; (17) is a high pressure air supply; (18) is an inlet fitting connecting the slim tube inside the pressure vessel to the pump and pressure transducers; (21 ) is an outlet fitting connecting the slim tube inside the pressure vessel to the back pressure regulator and the low side of the differential pressure transducer; (19) is a differential pressure transducer; and (20) is an absolute pressure transducer. DETAILED DESCRIPTION OF THE INVENTION

In one aspect, the present invention is a method for preventing the accumulation of toxic agents associated with corrosion inhibitors and their degradation products in a subterranean site adjacent to a water injection well of an oil reservoir by pretreating the well with a pacifying agent.

Applicants specifically incorporate the entire content of all cited references in this disclosure. Unless stated otherwise, all percentages, parts, ratios, etc., are by weight. Trademarks are shown in upper case. Further, when an amount, concentration, or other value or parameter is given as either a range, preferred range or a list of upper preferable values and lower preferable values, this is to be understood as specifically disclosing all ranges formed from any pair of any upper range limit or preferred value and any lower range limit or preferred value, regardless of whether ranges are separately disclosed. Where a range of numerical values is recited herein, unless otherwise stated, the range is intended to include the endpoints thereof, and all integers and fractions within the range. It is not intended that the scope of the invention be limited to the specific values recited when defining a range.

The following definitions are provided for the special terms and abbreviations used in this application: As used herein, the terms "comprises," "comprising," "includes," "including," "has," "having," "contains" or "containing," or any other variation thereof, are intended to cover a non-exclusive inclusion. For example, a composition, a mixture, process, method, article, or apparatus that comprises a list of elements is not necessarily limited to only those elements but may include other elements not expressly listed or inherent to such composition, mixture, process, method, article, or apparatus. Further, unless expressly stated to the contrary, "or" refers to an inclusive or and not to an exclusive or. For example, a condition A or B is satisfied by any one of the following: A is true (or present) and B is false (or not present), A is false (or not present) and B is true (or present), and both A and B are true (or present).

Also, the indefinite articles "a" and "an" preceding an element or component of the invention are intended to be nonrestrictive regarding the number of instances (i.e. occurrences) of the element or component.

Therefore "a" or "an" should be read to include one or at least one, and the singular word form of the element or component also includes the plural unless the number is obviously meant to be singular.

The term "invention" or "present invention" as used herein is a non- limiting term and is not intended to refer to any single embodiment of the particular invention but encompasses all possible embodiments as described in the specification and the claims.

As used herein, the term "about" modifying the quantity of an ingredient or reactant of the invention employed refers to variation in the numerical quantity that can occur, for example, through typical measuring and liquid handling procedures used for making concentrates or use solutions in the real world; through inadvertent error in these procedures; through differences in the manufacture, source, or purity of the ingredients employed to make the compositions or carry out the methods; and the like. The term "about" also encompasses amounts that differ due to different equilibrium conditions for a composition resulting from a particular initial mixture. Whether or not modified by the term "about", the claims include equivalents to the quantities. In one embodiment, the term "about" means within 10% of the reported numerical value, preferably within 5% of the reported numerical value. The terms "oil reservoir", and "oil-bearing stratum" may be used herein interchangeably and refer to a subterranean or sub sea-bed formation from which oil may be recovered. The formation is generally a body of rocks and soil having sufficient porosity and permeability to store and transmit oil.

As the term is used herein, "pacifying" or "pre-treating of a water injection site means altering the surface properties of permeable rock and sand in communication with a water injection well in such a way that the rock and sand will no longer adsorb or accept corrosion inhibitors and/or their degradation products that are in the injection water. Consequently the environment of the rock and sand in communication with the injection well does not become toxic to microorganisms and allows growth and activity of microorganisms used in MEOR.

"Water injection well" refers to a well through which water is pumped down into an oil producing reservoir for pressure maintenance, water flooding, or enhanced oil recovery.

"Bioremediation" refers to processes that use microorganisms to clean up oil spills or other contaminants from either the surface or the subterranean sites of an environment.

For the purposes of the present invention, the term "toxic zone" refers to a subterranean site adjacent to a water injection well comprising toxic concentrations of agents such as corrosion inhibitors or their degraded products which have adverse effects on growth and metabolic activities of microorganisms used in MEOR and/or bioremediation.

A "toxic agent", as the term is used herein, refers to a chemical that adversely affects growth and metabolic functions of microorganisms used in MEOR and/or bioremediation. A toxic agent may be a corrosion inhibitor or a degradation product of a corrosion inhibitor.

A "pacifying agent", as the term is used herein, is an agent that alters the surface properties of rock or sand in such a way as to reduce or eliminate the adsorption or accumulation of toxic agents. These toxic agents may be found in injection water.

The term "injection water" refers to fliud injected into oil reservoirs for secondary oil recovery. Injection water may be supplied from any suitable source, and may include, for example, sea water, brine, production water, water recovered from an underground aquifer, including those aquifers in contact with the oil, or surface water from a stream, river, pond or lake. As is known in the art, it may be necessary to remove particulate matter including dust, bits of rock or sand and corrosion by-products such as rust from the water prior to injection into the one or more well bores. Methods to remove such particulate matter include filtration, sedimentation and centrifugation.

The terms "inoculum of microorganisms" and "microbial inoculum" refer to a composition for the introduction concentration of viable microorganisms.

The term "water flooding" refers to injecting water through well bores into an oil reservoir. Water flooding is performed to flush out oil from an oil reservoir when the oil no longer flows on its own out of the reservoir.

The term "sweep efficiency" relates to the fraction of an oil-bearing stratum that has seen fluid or water passing through it to move oil to production wells during water flooding. One problem that can be encountered with water flooding operations is the relatively poor sweep efficiency of the water, i.e., the water can channel through certain portions of a reservoir as it travels from injection well(s) to production well(s), thereby bypassing other portions of the reservoir. Poor sweep efficiency may be due, for example, to differences in the mobility of the water versus that of the oil, and permeability variations within the reservoir which encourage flow through some portions of the reservoir and not others.

The term "biofilm" means a film or "biomass layer" of microorganisms. Biofilms are often embedded in extracellular polymers, which adhere to surfaces submerged in, or subjected to, aquatic environments. Biofilms consist of a matrix of a compact mass of microorganisms with structural heterogeneity, which may have genetic diversity, complex community interactions, and an extracellular matrix of polymeric substances.

The term "plugging biofilm" means a biofilm that is able to alter the permeability of a porous material, and thus retard the movement of a fluid through a porous material that is associated with the biofilm.

The term "simple nitrates" and "simple nitrites" refer to nitrate (NO3) and nitrite (NO₂), respectively.

Applicants have found that oil recovery processing aids, such as corrosion inhibitors, can accumulate in the area adjacent to a water injection well, and may build to concentrations that are toxic to microorganisms used in MEOR.

Corrosion inhibitors that can accumulate to levels that are toxic to microorganisms used in MEOR are, for example, inorganic corrosion inhibitors such as chlorine, hypochlorite, bromine, hypobromide and chlorine dioxide. Those used to combat corrosion caused by sulfate reducing bacteria (SRB) include, but are not limited to, nitrates (e.g., calcium or sodium salts), nitrite, molybdate, (or a combination of nitrate, nitrite and molybdate), anthraquinone, phosphates, salts containing chrome and zinc and other inorganics, including hydrazine and sodium sulfite (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 include: acetylenic alcohols, organic azoles, gluteraldehyde, tetrahydroxymethyl phophonium sulfate (THPS), bisthiocyanate acrolein, dodecylguanine hydrochloride, formaldehyde, chlorophenols, organic oxygen scavengers and various nonionic surfactants.

Other organic corrosion inhibitors include, for example, 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 into or on the subterranean site (e.g., permeable rock, sand stone, unconsolidated sand or limestone) or into the oil that has been trapped in the oil reservoir subterranean site. Long-term addition of these chemicals results in their accumulation and formation of a toxic zone in subterranean sites adjacent to a water well, with adverse effects on microbial inocula intended for MEOR.

A model system to simulate formation of a toxic zone can be used to study its effects on the survival of microorganisms. For example, a model system called a slim tube can be set up and packed with core sand from an oil well site. The model system as described herein, and shown in Figure 2, can be set up using tubing, valves and fittings compatible with the crude oil or the hydraulic solution used, that can withstand the range of applied pressure 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), which are used in a slim tube model system are commercially available and may be implemented by those skilled in the art.

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

In order to prevent the formation of a toxic zone, a subterranean site adjacent to a water injection well may be pre-treated with a pacifying agent. This pre-treatment involves contacting the subterranean site with a pacifying agent such that it enters the zone where toxic chemicals or agents would normally accumulate. The pacifying agent alters the surface properties of at least one of rock and sand (rock and/or sand) in such a way as to reduce or eliminate the adsorption or accumulation of toxic agents. A model slim tube system may be used to assess the efficacy of pacifying agents for preventing the formation of a toxic zone.

A pacifying agent is introduced through a water injection well to an area adjacent to the water injection well in a subterranean site. A schematic of a subterranean site adjacent to a water injection well is shown in Figure 1 .

Introduction of injection water containing a pacifying agent as shown in Figure 1 is one embodiment of the present method. The injection water (1 ) flows into the water injection well casing (7) which is inside the well bore (5) drilled through rock layers (2 and 3). A gap exists between the well casing (7) and the face (6) of the rock layer made by the well bore (5). Rock layer (2) represents impermeable rock above and below a permeable rock layer (3) that holds or traps oil. The injection water (1) flows down the well casing (7) and passes through perforations in the casing (5) and into fractures (4) in the permeable rock (3). This injection water then flows through the permeable rock layer (3) and introduces a pacifying agent to a watered zone (8) adjacent to the well bore. This zone extends radialy out from the well bore (5) in all directions in the permeable rock layer (3). While the volume of permeable rock (3) encompassed by the dash line (8) is illustrated only on one side of the well bore it actually exists on all sides of the well bore. This watered zone represents the subterranean site adjacent to the water injection well.

Pacifying the rock and/or sand in subterranean sites adjacent to water injection wells may be achieved using a composition comprising a pacifying agent. Any agent that alters the surface properties of the rock or sand in such a way as to disallow the adsorption or accumulation of toxic agents found in the injection water used in a site, may be used as a pacifying agent. Pacifying agents may include surfactants that adhere to the surface of rock and/or sand, waxes such as a paraffin dispersion, and relatively inert water dispersed polymer agents. Surfactants may include fluorosurfactants, anionic

surfactants, cationic surfactants, nonionic surfactants as well as zwitterionic surfactants. In one embodiment pacifying agents are aqueous dispersions of polymers including Teflon® PTFE (polytetrafluoroethylene) Fluoropolymer Resins produced by the DuPont Company (Wilmington DE). Typically a wetting agent is used to stabilize particle dispersions of Teflon® PTFE

Fluoropolymer Resins.

In the present method, following contacting a subterranean site with a pacifying agent, the subterranean site is contacted with a corrosion inhibitor. Typical corrosion inhibitors are described above. Once the permeable rock and/or sandadjacent to the injection well in the subterranean site is pacified, corrosion inhibiters will thereafter remain in injection water flowing through the well and adjacent site without adsorbing to the rock or sand. A combination of radial flow, dispersion and desorption may allow the solubilized corrosion inhibitors 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 reservoir. Following dilution and dispersion of the corrosion inhibitors over a much larger area, their concentrations within the subterranean site of the well may be reduced to non-toxic levels for MEOR microorganisms. However, even if the corrosion inhibitor concentrations were still at toxic levels, the pacifying agent prevents the formation of a toxic zone in the subterranean site adjacent to the injector well. Thus, a microbial inoculum may pass through the subterranean site adjacent to the water injection well without encountering toxic levels of corrosion inhibiters.

In a MEOR process, viable microorganisms are added to the water being injected into a water injection well providing an inoculum of

microorganisms that contacts the adjacent subterranean site. The microbial inoculum contains at least one strain of microorganism. The introduced microorganisms grow and propagate to colonize the subterranean sites adjacent to the water injection well to perform oil recovery enhancing functions. In the present method, the subterranean site is brought in contact with a microbial inoculum following contact with a corrosion inhibitor, which in turn follows contact with a pacifying agent.

Microorganisms useful for this application may be any microorganism that aid in oil recovery. Microorganisms that promote the release of oil and/or that form plugging biofilms to block highly permeable zones in an oil reservoir thereby improving sweep efficiency may be used. The microorganisms may comprise classes of facultative aerobes, obligate anaerobes and denitrifiers. 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. Techniques and various suitable growth media for 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" (A. L. Demain and N. A. Solomon, ASM Press, Washington, DC, 1986) and "Isolation of Biotechnological Organisms from Nature", (Labeda, D. P. ed. p1 17- 140, McGraw-Hill

Publishers,1990).

Examples of microorganisms useful in a microbial inoculum in the present method include, but are not limited to: Shewanella species including Shewanella putrefaciens (ATCC PTA-8822) and Shewanella sp L3:3 (ATCC PTA-10980), 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 (ATCC PTA-8822) may be used to inoculate the subterranean site. In another embodiment Pseudomonas stutzeri (ATCC PTA8823) may be used to inoculate the subterranean site. In another embodiment Thauera aromatica (ATCC9497) may be used to inoculate the subterranean site.

Recovery of oil following introduction of a microbial inoculum may be by methods known to one skilled in the art. Typically secondary oil recovery methods are used such as water flooding. Water flooding involves injection of water through well bores into the oil reservoir. As water moves into the reservoir from an injection well and moves through the reservoir strata, it displaces oil to one or more production wells where the oil is recovered.

Action of the microorganisms grown from the microbial inoculum improves sweep efficiency to enhance oil recovery. 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:

Chemicals 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, Ml), GIBCO/BRL (Gaithersburg, MD), or Sigma

Chemical Company (St. Louis, MO), unless otherwise specified.

Amines analysis

Concentration of amines, in media and water, were analyzed by gas chromatography (GC) using an Agilent Model 5890 (Agilent, Wilmington, DE) GC equipped with a flame photoionization detector and a split splitless injector, and 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 -Dodecaneamine (Aldrich). Helium was used as the carrier gas. A temperature gradient of 50 degrees Celsius (°C) to 250 °C at 30 °C increase per minute (min) was used. Retention times (in minutes, min) for various chemicals of interest included: N,N- Dimethyl-1 -Dodecaneamine (8.08 min); N,N-Dimethyl-1 -Tetradecaneamine (8.85 min); N,N-Dimethyl-1 -Hexadecane- amine (9.90 min); N,N-Dimethyl-1 - Octadecaneamine (10.26 min) and N-Methyl,N-Benzyll-1 -Tetradecaneamine (1 1 .40 min).

Determination of viable cell titer (most probable number)

In order to determine viable cell titer, samples from cultures or slim tubes were diluted by 1 :10 serial dilution in 8 rows per sample of a 96 well plate using standard Miller's Luria Broth or Luria Broth with 3.5 % NaCI added. Titration was done using an automated Biomek200 robotic pipettor. Growth was determined by visual turbidity and recorded for each of 8 rows. The most probable number algorithm of Cochran (Biometrics (1950) 6:105-1 16) was used to determine the viable cells/ml and the 95% confidence limits for this number in the original sample.

The serial dilution method plating was used to determine the bacterial titer of such cultures. A series of 1 :10 dilutions of such samples was plated and the resulting colonies were counted. The number of colonies on a plate was then multiplied by the dilution factor (the number of times that the 1 :10 dilution was done) for that plate to obtain the bacterial count in the original sample.

EXAMPLE 1

ESTABLISHING A TOXIC ZONE IN CORE SAND FROM AN OIL WELL USING A MIXTURE OF AMINES IN A MODEL SYSTEM

A sample of sand obtained from the Schrader Bluff formation at the Milne Point Unit of the Alaska North Slope was cleaned by washing with a solvent made up of a 50/50 (volume/volume) mixture of methanol and toluene. The solvent was subsequently drained and then evaporated off the core sand to produce clean, dry, flow able core sand. This core sand was sieved to remove particles of less than one micrometer in size and was then packed tightly into a four foot (121 .92 cm) long flexible slim tube (9, Figure 2) and compacted by vibration using a laboratory engraver. Both ends of the slim tubes were capped to keep the core sand in it. The complete apparatus is shown in Figure 2. Tubing that can sustain the amount of pressures used in the slim tube, was connected to the end caps. The slim tube (9) was mounted into the pressure vessel (10) with tubing passing through the ends (11 and 12) of the pressure vessel using pressure fittings (18 and 21 ). Additional fittings and tubing were used to connect the inlet of the slim tube (11 ) to a pressure pump (13) and a feed reservoir (14).

Additional fittings and tubing connected the inlet of the slim tube to an absolute pressure transducer (20) and the high pressure side of a differential pressure transducer (19). Fittings and tubing connected the outlet of the slim 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 ported to a computer and the pressure readings were monitored and periodically recorded. The pressure vessel (10) around the slim tube was filled with water through a water port (15). This water was then slowly pressurized with air (17) to a pressure of about 105 pounds per square inch (psi) (0.72 mega Pascal) while brine #1 (Table 1 ) from the feed reservoir (14) flowed through the slim tube and left the slim tube through the back pressure regulator (16). This operation was performed such that the pressure in the slim tube was always 5 to 20 psi (0.034 - 0.137 mega Pascal) below the pressure in the pressure vessel (10).

TABLE 1

Ingredients of Brine #1

(no nutrient brine - gram per liter (qr/L) of tap water

NaHCO₃ 1 .38 grams (gr)

CaCI₂ ^*6H₂O 0.39 gr

MgCI₂ ^*6H₂O 0.220 gr

KCI 0.090 gr

NaCI 1 1 .60 gr

NaHCOs 1 .38 gr

Trace metals 1 ml

Trace vitamins 1 ml

Na₃(PO₄) 0.017 gr (=10 parts per million (ppm) PO₄)

NH4CI 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 HCI or NaOH and the solution was filter sterilized.

TABLE 2

Concentration of the amines added to Brine #1

Once the pressure inside and outside the slim tube was established, one pore volume of crude oil from an oil reservoir of the Milne Point Unit of the Alaskan North Slope was pumped into the slim tube. This process was performed in several hours (h). Once the crude oil had saturated the core sand in the slim tube and was observed in the effluent, the flow was 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 slim tube at a rate of ~1 .5 - 3.5 milliliter per hour (ml/h) (~1 pore volume every 20 h). Samples were taken from the effluent and the concentration of natural microflora in them was determined as in General Methods.

After 51 pore volumes of flow through the slim tube the concentration of natural microflora in the system was about 1 x10⁷ colony forming units per milliliter (CFU/ml). At this point, a mixture of amines (hereafter amines/brine mixture) was added at 150 ppm concentration to brine #1 . The amines mixture was prepared by vigorously agitating a solution of 6 wt% benzalkonium chloride and 7% sodium nitrate. After resting overnight an aliquot was diluted 600:1 and analyzed. 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-1 -dodecaneamine, N-N-dimethyl-1 -tetradecane- amine, N-N-dimethyl-methane-thioamide, caprolactam and N-methyl-N-benzyl-1 - tetradecaneamine. Two of the components were identified as amines but specific chemical formulas could not be assigned to them because the Mass Spectral Fragmentation patterns could not be deciphered. These are labeled in Table 2 as "minor amine" and "other amine". Analysis of the effluent from the slim tube did not indicate the presence of any amines in it. The

experiment was continued by pumping 150 ppm of the mixture of amines in brine #1 through the slim tube.

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

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

After 24 pore volumes of the amines-free brine#1 had been pumped through the slim tube, 51 ppm of amines was detected in the effluent. The slim tube was then inoculated with one pore volume of Shewanella

putrefaciens (ATCC PTA-8822) at a concentration of approximately 1 x10⁹ CFU/ml. This inoculation was not allowed to remain in the slim tube. Instead, amines-free brine#1 was flushed through the slim tube immediately after the inoculation. Consequently the microbes resided in the slim tube for only a few hours during the transit through it. Thus, it was anticipated that the

microorganisms' concentration in the effluent could be measured in the effluent eluting the slim tube. However, remarkably no microorganisms

(representing about a 9 log kill) were detected in the slim tube effluent despite the short residence time of the inoculum in the slim tube. This experiment confirmed that a toxic zone had been established in the slim tube. In a continued attempt to detoxify the slim tube, brine #1 alone was continuously pumped through it.

After 79 pore volumes of the amines-free brine #1 had been pumped through the slim tube, the amines concentration in the effluent of the slim tube was measured at 30 ppm. The slim tube was inoculated with another pore volume of Shewanella putrefaciens (at 1 x10⁹ CFU/ml). The CFU/ml in an effluent sample was about 1 x10⁴ showing more than a 5 log kill of this microorganism had occurred immediately following inoculation. This experiment underlined the continued toxic effect of the amines

despite extended washing of the tube with the amines-free brine#1 solution.

After 108 pore volumes of the amines-free brine #1 had been pumped through the slim tube, the amine concentration in the effluent was measured at 5 ppm. The slim tube was inoculated with an additional one pore volume of Shewanella putrefaciens containing 1 x10⁹ CFU/ml. The CFU/ml in the effluent sample of the slim tube immediately following inoculation indicated a 4 - 5 log kill of this microorganism despite the extended washing with the amines-free brine#1 and the decrease in the amines concentration in the effluent. These results further confirmed the continued toxic effect of the mixture of amines accumulated in the slim tube.

After 143 pore volumes of the amines-free brine #1 had been pumped through the slim tube one pore volume of an inexpensive odorless mineral spirits (OMS)(Parks OMS, Zinsser Co., Inc., Somerset Jew Jersey #2035 CAS #8052-41 -3) was pumped through the slim tube in an attempt to remove the remaining mixture of amines. After this flush of OMS, pumping of amines-free brine #1 through the slim tube was continued.

After 149 pore volumes of amines-free brine #1 had been pumped through the slim tube, the amines concentration in the effluent was measured at 4 ppm and the slim tube was inoculated with an additional one pore volume of Shewanella putrefaciens (1 x10⁹ CFU/ml). A count of microorganisms in the sample of the slim tube's effluent showed a 2 - 3 log kill (99 to 99.9%) despite the OMS flush and the extended washing with the amines-free brine#1 . These results confirmed that the toxic zone in the slim tube was still killing virtually all the microorganisms added to the tube. After 168 pore volumes of the amines-free brine #1 had been pumped through the slim tube, one pore volume of a solution of 10% HCI in water was pumped through the slim tube to remove the amines. After this acid wash, the amines-free brine #1 was continuously pumped through the slim tube.

Following the acid wash treatment, an additional 2 pore volumes of the amines-free brine #1 was pumped through the slim tube and the amines concentration in the effluent was measured at 0.5 ppm. The slim tube was then inoculated with an additional one pore volume of Shewanella

putrefaciens (1 x10⁹ CFU/ml). The CFU/ml in the effluent showed about a 0.4 log kill of this microorganism. These results underlined survival of more microorganisms following the acid wash of the slim tube and the effectiveness of using an acid to detoxify the toxic zone in the slim tube. Table 3 below summarizes results of the various tests described above.

TABLE 3

Summary of the amount of amine observed in the slim tube's effluent and the fraction of the microorganisms killed (log kill) during residence in the slim tube.

PV = pore volume; nd= not detected

EXAMPLE 2 (PROPHETIC)

PRETREATMENT OF CORE SAND IN A SLIM TUBE TO AVOID TOXIC

ZONE FORMATION

Teflon® PTFE Fluoropolymer Resin Aqueous Dispersions are used to pretreat a slim tube in order to passivate the resident core sand and avoid formation of a toxic zone.

DuPont Teflon® PTFE (polytetrafluoroethylene) aqueous dispersions are milky white dispersions of PTFE particles in water, stabilized by wetting agents. A sample of the sand obtained from the Schrader Bluff formation at the Milne Point Unit of the Alaska North Slope is cleaned by washing with a solvent made up of a 50/50 (volume/volume) mixture of methanol and toluene. The solvent is subsequently drained and is evaporated off the core sand to produce clean, dry, flowable core sand. This core sand is sieved to remove particles of less than one micrometer in size and is then packed tightly into a four foot (121 .92 cm) long flexible slim tube (9, Figure 2) as described in Example 1 . A complete apparatus is shown in Figure 2 and described in Example 1 is prepared.

Once the pressure inside and outside the slim tube is established, one pore volume of crude oil from an oil reservoir of the Milne Point Unit of the Alaskan North Slope is pumped into the slim tube. This process is performed in several hours (h). Once the crude oil saturates the core sand in the slim tube and is observed in the effluent, the flow is stopped and the oil is allowed to age in the core sand for 3 weeks. At the end of this time, brine #1 is pumped through the slim tube at a rate of ~1 .5 - 3.5 milliliter per hour (ml/h) (~1 pore volume every 20 h). Samples are taken from the effluent and the concentration of natural microflora in them is determined. After 10 pore volumes of brine #1 flow through the slim tube, a dispersion of Teflon® PTFE Fluoropolymer Resin Aqueous Dispersion Type TE3859 (DuPont Co.

Wilmington, DE), a 60% dispersion in water, is flushed through the slim tube for 1 pore volume. The slim tube is shut in for 5 days while the Teflon® PTFE Fluoropolymer Resin Aqueous Dispersion is allowed to soak into the sand matrix. After 5 days of shut in, flow of brine #1 resumes.

After 51 pore volumes of flow through the slim tube the concentration of natural microflora in the system may be about 1 x10⁷ colony forming units per milliliter (CFU/ml). At this point, a mixture of amines (hereafter amines/brine mixture) is added at 150 ppm concentration to brine #1 . The approximate composition of the mixture of amines is in Table 2 as described in Example 1The experiment is continued by pumping 150 ppm of the mixture of amines in brine #1 through the slim tube.

After 2 pore volumes of the mixture of brine #1 with 150 ppm of mixture of amines is pumped into the slim tube, 100 ppm of amines are observed in the effluent. After 80 pore volumes of the mixture of brine #1 with 150 ppm of mixture of amines is pumped into the slim tube a total of about 1 gr of the mixture of amines has flowed through the slim tube. At this point, 150 ppm of amines is observed in the effluent of the slim tube. Virtually all the amine pumped into the slim tube is accounted for in the effluent. In addition, at this time, the natural microflora is easily seen in the effluent and the concentration of natural microflora in the effluent is about 1 x10⁷ colony forming units per milliliter (CFU/ml).. This is evidence that the treatment with the fluorocarbon dispersion effectively pacified the sand surface and makes it virtually impossible for the any toxic chemicals added to the sand to accumulate and create a toxic zone detrimental to microorganisms.

Claims

CLAIMS What is claimed is:

1 . A method for treating an oil reservoir comprising:

b) contacting the subterranean site with a pacifying agent;

c) contacting the subterranean site with at least one corrosion inhibitor; and

d) contacting the subterranean site with a microbial inoculum

containing at least one strain of microorganism,

wherein the steps are performed in the listed order and wherein formation of a toxic zone in the subterranean site is reduced.

2. The method of claim 1 wherein contacting the subterranean site in (a), (b), and (c) is by introduction through the water injection well.

3. The method of claim 1 wherein the pacifying agent is a substance that reduces adsorption of toxic agents to at least one of rock and sand

4. The method of claim 3 wherein the pacifying agent is an inert water dispersed polymer agent.

5. The method of claim 4 wherein the polymer agent is

po!ytetrafiuoroethy!ene

6. The method of claim 1 wherein the corrosion inhibitor is an organic or inorganic compound.

7. The method of claim 1 wherein the microorganism of the microbial inoculum of (d) grows in the presence of oil under denitrifying conditions.

8. The method of claim 7 wherein the microorganism is selected from the group consisting of Comamonas terrigena, Fusibacter paucivorans, Marinobacterium georgiense, Petrotoga miotherma, Shewanella sp. L3:3, Shewanella putrefaciens, Pseudomonas stutzeri, Vibrio alginolyticus, Thauera aromatica, Thauera chlorobenzoica and Microbulbifer hydrolyticus.

9. The method of claim 1 further comprising recovering oil from the

subterranean site.