US20120241148A1

US20120241148A1 - Control of fluid flow during treatment of subterranean sites using well fluid injection

Info

Publication number: US20120241148A1
Application number: US13/241,361
Authority: US
Inventors: Albert W. Alsop; Scott Christopher Jackson
Original assignee: EI Du Pont de Nemours and Co
Current assignee: EIDP Inc
Priority date: 2010-09-29
Filing date: 2011-09-23
Publication date: 2012-09-27
Also published as: CO6670563A2; EP2622175A1; WO2012050794A1; RU2013119601A; BR112013007630A2; CA2812719A1; CN103154430A; MX2013003588A

Abstract

Disclosed herein is a method to control distribution of injected microorganisms, nutrients or other chemical treatment fluids from a single injection well to multiple production wells. The sweep efficiency is improved preventing premature production of fluids from production wells with short breakthrough times. This is a useful technique for treatment of subterranean target sites for practice of Microbial Enhanced Oil Recovery and bioremediation.

Description

This application claims the benefit of U.S. Provisional Application 61/387,494, filed Sep. 29, 2010.

FIELD OF INVENTION

This disclosure relates to the field of enhanced oil recovery or bioremediation. More specifically, it relates to controlling flow of treatment fluids and/or microorganisms into subterranean strata to enhance oil recovery or bioremediation.

BACKGROUND OF THE INVENTION

Primary techniques used in oil recovery 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 sites are locations where wells have been drilled into a subterranean stratum, containing oil, with the intent to produce oil from that stratum. An oil reservoir typically refers to a deposit of subterranean oil in a subterranean stratum. Secondary oil recovery methods, such as water flooding, that is injection of water through injection wells into the oil reservoir, have been used to force oil through the subterranean strata toward production wells and thus improve recovery of the crude oil (Hyne, N. J., 2001, “Non-technical guide to petroleum geology, exploration, drilling, and production”, 2nd edition, Pen Well Corp., Tulsa, Okla., USA). Production and injection wells are channels made by a well bore from the surface to the subterranean oil bearing strata with enough size to allow for pumping of fluids either from the surface and into the strata (injection wells) or from the strata to the surface (production wells). Configuration of injection and associated production wells for enhanced oil recovery and bioremediation may take many forms, as is well known in the art (“Standard Handbook of Petroleum & Natural Gas Engineering”, 2nd Edition, Editors, William C. Lyons, Ph.D., P.E., Gary J. Plisga, B.S., Gulf Publishing, Elsevier, Burlington, Mass., USA).
Enhanced oil recovery (EOR) methods that utilize surfactant, polymer, alkali and microbial treatments have been known to improve water flooding performance of subterranean target sites. Subterranean target sites refer to any subterranean site that is subject to treatment for EOR, microbial enhanced oil recovery (MEOR) or bioremediation. As water moves through the reservoir, it displaces oil therein to one or more production wells through which the oil is recovered. One problem commonly encountered with water flooding operations is that the heterogeneity of the subterranean strata can lead to reduced sweep efficiency of the water. Sweep efficiency is related to the fraction of the oil-bearing subterranean stratum that has seen water passing through it in order to move oil to the production wells. Sweep efficiency can be reduced by several factors such as high permeable streaks, geometry of the wells and the strata, and viscous fingering. In such cases, water preferentially channels through the watered-out strata of the oil reservoir as it travels from the injection well to the production wells, thus bypassing the subterranean oil-bearing strata that are not watered-out. In watered-out areas the injection water has preferentially flowed through these strata and has removed most of the oil in that strata in contrast to adjacent strata that have seen little or no water.
Various methods have been used to combat poor sweep efficiency. U.S. Pat. No. 4,561,500 describes a method of reducing permeability of the underground formation by injecting microorganisms capable of producing insoluble exopolymers which accumulated in higher permeability zones. WO2005005773 describes increasing sweep efficiency during oil recovery by injecting a consortium of microorganisms that produce surfactants. U.S. Pat. No. 3,771,598 discloses injection of a mobilizing fluid into an injection well at a predetermined pressure and increasing the pressure in the formation by throttling outflow at the production well. U.S. Pat. No. 4,184,549 discloses application of a low-viscosity fluid which forms a high-viscosity coarse emulsion with residual hydrocarbons thus reducing the permeability of the stratum to fluids.
With the ever-increasing demand on oil, there is a constant need for methods to improve recovery of oil from oil reservoirs thus development of novel techniques to improve sweep efficiency during EOR is desired.

SUMMARY OF THE INVENTION

The disclosed method is a method for treatment of a subterranean target site during oil recovery or bioremediation by controlling distribution of a well treatment fluid into said target site, the method comprising the steps of:

- a) determining fluid flow patterns of injection fluid between an injection well and one or more production wells in the subterranean site;
- b) injecting a well treatment fluid in the subterranean site; and
- c) controlling the distribution of the well treatment fluid amongst the production wells,

wherein oil recovery is improved.

BRIEF DESCRIPTION OF FIGURES OF THE INVENTION

FIG. 1 depicts an inverted five spot injection well (1) and production wells (2) system.

DETAILED DESCRIPTION OF THE INVENTION

According to the disclosed method, during treatment of a subterranean target site, for EOR or bioremediation, fluid flow is controlled to ensure that well treatment fluids flow from the injection well to all of the surrounding production wells and are distributed throughout the subterranean strata so that adequate volumes of well treatment fluids flow to all areas of the subterranean strata without bypassing some areas and without excessive loss of fluids out of one or more production wells with short breakthrough time. The volume of fluid that can be produced from a production well between the time a well treatment fluid is introduced at an injection well and the time that a significant amount of that well treatment fluid is seen at a production well is known as the “breakthrough volume” for that injection and production well pair. At a constant flow rate of production, the elapsed time required for a breakthrough volume to be produced is defined as the “breakthrough time” for that injection and production well pair. “Short breakthrough time”, as used herein, refers to a breakthrough time that is shorter than the time required for the well treatment fluid to affect the desired changes in the subterranean target site and improve sweep efficiency. For example, it can be the time required for MEOR microorganisms to consume nutrients in nutritional chemical fluids used as treatment fluids (e.g., less than one day for low salt fluids, and less than 5 days for high salt fluids). Low salt fluids are those well treatment fluids that contain less than 17 parts per thousand (ppt) of sodium chloride (hereafter referred to as “salt”) and high salt fluids are well treatment fluids that contain 50-60 ppt or higher levels of salt.
One example of a suitable configuration of an injection well and associated production wells in an oil reservoir, which is a subterranean target site, is shown in FIG. 1. The single injection well (1) is in the center of the pattern and is labeled as “I”. There are four flow paths illustrated with arrows pointing away from this single injection well to the production wells (2): P-1, P-2, P-3 and P-4. Other flow paths are possible depending on the nature of the rocks at the subterranean target site.
Any one of the flow paths illustrated in FIG. 1 can take significantly more of the introduced well treatment fluid and channel it to a particular production well and thus bypass parts of the subterranean target site. This phenomenon can cause treatment of only some parts of the subterranean target site and loss of well treatment fluids out of one or more producing wells before the well treatment fluid can affect the desired changes necessary to improve sweep efficiency and to increase oil production from the subterranean target site. The method disclosed herein allows for detection and elimination of this undesirable bypassing.
The fluid useful for water flooding according to the present method comprises water. Water can be supplied from any suitable source, and can 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, e.g., filtration, sedimentation and centrifugation, are well known in the art.
According to the disclosed method, before starting use of any treatment fluid, such as chemical treatment fluids optionally including microorganisms, an analysis of the fluid flow pattern between an injection well and one or more production wells in the target subterranean site and the breakthrough volumes of the production wells is made. Reservoir modeling, tracer testing, approximation methods, or any other method well known in the art can be used to estimate the breakthrough volume of any production well.
In the currently disclosed method determination of distribution of the well treatment fluid allows identification of any particular flow path (e.g., as illustrated in FIG. 1) which takes significantly more of the well treatment fluid and channels it to a particular production well thus bypassing some parts of the subterranean target site. Chemical or radioisotope tracer tests are common methods used in the oil industry to determine such bypassing and are suitable for use in the present invention. Tracer chemicals used for this purpose include anions such as bromine, iodine, and nitrate or dyes such as the sodium salt of Fluorescein dye, commonly known as Uranine (CAS 518-47-8, Part number A833-500, Fisher Scientific, Pittsburgh, Pa.). Radioisotope tracers such as hexacyanocobaltate, thiocyanate, tritiated water, halides or alcohols that contain radioisotope elements like Cobalt 60, Cobalt 58, Cobalt 57, Carbon 14, Tritium, Sulfur 35, Chlorine 36 or Iodine 125 are often used for tracer tests.
In the currently disclosed method, when lack of distribution of fluid to some parts of the subterranean target site is found and it is determined that some production wells have short breakthrough times which would result in unacceptable loss of well treatment fluid through bypassing between the injection well and one or more production wells, the flow through these production wells is controlled during treatment to allow distribution of the well treatment fluid throughout the subterranean target site and in particular to the areas that have not been watered-out.
By using the determined breakthrough times for several injection to production well pairings it is possible to sequentially restrict (or throttle) the flow of treatment fluid by partially closing the production valves or alternatively completely shutting off the flow from the production wells with short breakthrough times. This allows the treatment fluid to penetrate throughout the subterranean strata between the injection well and production wells with longer breakthrough times, and to provide for treatment across an entire subterranean target site. As used herein, the terms “restricting or throttling the flow” refers to reducing the flow from one or more production wells in order to allow the well treatment fluid to get distributed through the subterranean target site.
In instances where MEOR is used, sequential shut off or throttling of production wells allows microbial inocula to be distributed into the subterranean strata thus allowing the nutritional chemical fluids and the inocula to move deeper into the reservoir without losing the inoculum and/or the nutritional chemical fluid through production wells with short breakthrough times. As used herein, the terms “inoculum and inocula”, refer to microorganisms introduced into an injection well in a well treatment fluid.
In the current method, “nutritional chemical fluids” refers to a fluid used for growth and colonization of either native microorganisms of the subterranean target site or exogenously added microorganisms for MEOR applications. “Native microorganisms”, as used herein, refers to a variety of microorganisms that naturally exist in the subterranean target site. “Exogenous microorganisms” or “exogenously added microorganisms” refers to microorganisms that are grown outside of the subterranean target site and then introduced into the site. This may include microorganisms that were isolated from the target or other subterranean site and then grown outside of the subterranean site before introduction.
In one embodiment, the well treatment fluid can be a chemical treatment fluid and can comprise one or more polymeric fluids. Polymeric fluids useful for the current method include, but are not limited to, water soluble polymers such as carboxymethylcellulose, hydroxyethylcellulose, carboxymethylhydroxyethylcellulose, guar gum, hydroxypropyl guar, carboxymethylhydroxypropyl guar, polyacrylamide, polyamines, xanthan, polysaccharides or polyvinylalcohol derivatives as those disclosed in commonly owned U.S. Pat. No. 7,6677,305, or polymers of 1,3 propanediol as disclosed in commonly owned and co-pending U.S. Patent Application 20090197779, which are herein incorporated by reference in their entireties.
In another embodiment, the chemical treatment fluids may also comprise one or more surfactants. The one or more surfactants useful for the current method include, but are not limited to: anionic sulfonates, nonionics (ethylene oxide derivatives), quaternary ammonium compounds, fluorosurfactants, amphoterics and glycol ethers or a mixture thereof.
In another embodiment, the chemical treatment fluid may comprise at least one base having pKa above 10 wherein the resulting pH of the well treatment fluid is greater than 10. Bases useful in the practice of the present invention include, but are not limited to: sodium silicate, sodium hydroxide or sodium carbonate or a mixture thereof. The treatment can include any combination of polymer, surfactant and alkali treatment chemicals used at once or used in sequence. The treatment fluid may also be a low salt fluid.
The treatment fluid can also be composed of a nutritional chemical fluid used by microorganisms to grow and to express a biological function resulting in improved oil recovery. The nutritional chemical fluid may contain a suspension of microorganisms. Microorganisms (i.e., native microorganisms or exogenously added microorganisms) can be used in the current method to improve sweep efficiency and/or reduce residual oil saturation of rock in the subterranean site. Many microorganisms live in various parts of subterranean strata and comprise the native microorganisms of such strata. According to the current method, in one embodiment, nutritional chemical fluids are introduced into the subterranean strata which encourage colonization and propagation of the native microorganisms in more permeable strata where they plug the pores of the permeable strata and thus block water flow through them. Native microorganisms or exogenous microorganisms that grow in a subterranean site using nutritional chemical treatment fluids may also release oil from rock thereby reducing residual oil saturation.
In the current method, microorganisms can be exogenously added to improve sweep efficiency and/or reduce residual oil saturation. Microorganisms useful in the current method can comprise classes of facultative anaerobes, obligate anaerobes and denitrifiers. Various species of microorganisms (bacteria and fungi) that can be used to improve sweep efficiency and enhance oil recovery include, but are not limited to, the genera: Pseudomonas, Bacillus, Actinomycetes, Acinetobacter, Arthrobacter, Schizomycetes, Corynebacteria, Achromobacteria, Arcobacter, Enterobacteria, Nocardia, Saccharomycetes, Schizosaccharomyces, Vibrio, Shewanella, Thauera, Petrotoga, Microbulbifer, Marinobacteria, Fusibacteria, and Rhodotorula. The terms “genus” and “genera”, as used herein, refer to the category of microorganisms ranking below a “family” and above a “species” in the hierarchy of taxonomic classification of microorganisms. The term “species” refers to a group of microorganisms that share a high degree of phenotypic, biochemical and genotypic similarities.
In various embodiments the inoculum can comprise only one particular species, or two or more species of the same genera, or a combination of different genera of microorganisms.
If well treatment fluids comprising microorganisms are used for improving sweep efficiency, then chemical well treatment fluid can comprise one or more nutritional chemical fluids. Nutritional chemical fluids useful in the present invention include those containing at least one of the following elements: C, H, O, P, N, S, Mg, Fe, or Ca. By way of example only, inorganic compounds that may be used include PO₄ ²⁻, NH₄ ⁺, NO₂ ⁻, NO₃ ⁻, and SO₄ ²⁻ amongst others. Techniques and various suitable nutrient-containing fluids for growth and maintenance of facultative and strict anaerobic microorganisms are well known in the art.
Growth substrates can include sugars, organic acids, alcohols, proteins, polysaccharides, fats, hydrocarbons or other organic materials known in the art of microbiology to be subject to microbial decomposition. Major nutrients containing nitrogen and phosphorus (non-limiting examples can include NaNO₃, KNO₃, NH₄NO₃, Na₂HPO₄, K₂HPO₄, NH₄Cl); vitamins (non-limiting examples can include folic acid, ascorbic acid, and riboflavin); trace elements (non-limiting examples can include B, Zn, Cu, Co, Mg, Mn, Fe, Mo, W, Ni, and Se); buffers for environmental controls; catalysts, including enzymes; and both natural and artificial electron acceptors.

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 without departing from the scope thereof, can make various changes and modifications of the invention to adapt it to various usages and conditions.

Abbreviations Used in the Examples

“h” means hour(s); “L” means litre; “° C.” means degrees Celsius; “mg” means milligram(s); “mm” means millimeter; “kg” means kilogram(s); “ppt” means part per thousand; “mM” means millimolar; “%” means percent; “min” means minute(s); “mL/min means milliliter per minute; “D” means day(s); “μg/L” means microgram per liter; “nM” means nanomolar; “μM” means micromolar.

Example 1

Prophetic

To Determine Breakthrough Times in Production Wells

The breakthrough time for each production well is determined using a tracer chemical such as a sodium salt of Fluorescein dye, commonly known as Uranine (CAS 518-47-8, Part number A833-500, Fisher Scientific, 2000 Park Lane Drive, Pittsburgh, Pa. 15275).
Uranine (2.7 kilogram, kg) is added to a tank containing 9,000 L of water. The normal flow of injection water to the injection well to be tested is shut off. The Uranine treated water is injected over a 7.2 hours (h) period into the injection well at a rate of injection equal to 1,250 L/h which is the normal injection flow rate. Upon completion of the injection of the 9,000 L of Uranine solution, the normal injection flow of water is restored at the normal injection rate of 30,000 L/D. After the start of Uranine injection, samples are taken from the associated production wells at various time intervals for example, 6, 12, 18, 24, 36, 48 h following initial tracer fluid injection and it is then followed by taking samples at longer intervals. For examples samples are taken at daily intervals. The samples are allowed to settle and separate into water and oil layers. The water layer is removed and placed in a small clear glass sample vial and its color is visually compared against similar tubes of injection water prepared with known concentrations of Uranine. In the art, it is generally understood that very low concentrations of Uranine in water can be visually estimated. Thus by visual comparison with known standards the dye concentration in the water samples can be estimated. By comparing relative concentrations of Uranine in the samples obtained from various production wells, the relative breakthrough times for various wells can be estimated and wells with shorter breakthrough times can be identified. Then flow to those wells can be restricted in order to allow equal distribution of injected treatment fluid into the subterranean target site to improve sweep efficiency and assist oil recovery.

Example 2

Prophetic

To Inoculate a Subterranean Site without Loss of Microbial Inoculum

In this example, the injection and production wells of a subterranean site are arranged in an inverted five spot pattern as shown in FIG. 1. For the purposes of this example, it is assumed that production well P2 has the shortest breakthrough time followed by production well P4 with the second shortest breakthrough time. A microbial inoculum suspension is prepared by making in a 6,000 L tank a nutritional chemical fluid appropriate for the particular microorganism used. A microbial inoculum is then added to the nutritional chemical fluid to produce a suspension at the desired concentration of microbes and nutrients.
The following steps are then taken:
1) Shut off the normal injection water flow into injection well.
2) Inject the inoculum suspension into the injection well at the normal injection rate for the injection well (i.e., 1,250 L/h for 4.8 h)
3) After start of injection of inoculum into the injection well, at various time intervals shut in production well P-2. Production is shut in by shutting off the producer pump for a period of time such as 2 out of 3 hours, or by reducing the stroke frequency such as operating at 20 cycles per minute rather than 60 cycles per minute.
4) Complete injection of the inoculum suspension.
5) Open production well P-2 flow valve after inoculum injection is complete.
6) Inject water into the injection well at the standard injection rate (e.g., 1,250 L/h for 24 h) to push the microbial inoculum to desired depths of the subterranean target site.
7) After start of water injection into the injection well, at various time intervals shut in production well P-2.
8) After start of water injection into the injection well, at various time intervals shut in producer well P-4.
9) Complete injection of water into the injection well
10) Open production wells P-2 and P-4 after injection of water into the injection well is complete.
11) Inject for example 2,000 L of nutritional chemical fluid at the standard flow rate (e.g., 1,250 L/h for 1.6 h) into the injection well
12) Inject water at standard injection rate (e.g., 1,250 L/h for 24 h) into the injection well to push nutritional chemical fluid to desired depths of reservoir.
13) After start of water injection into the injection well, at various time intervals shut in production well P-2.
14) After start of water injection into the injection well, at various time intervals shut in production well P-4.
15) Upon completion of injection into the injection well, shut off the injection flow to the injection well.
16) Allow well treatment fluids a number of days to contact the subterranean strata and perform their function.
17) Restart injection flow into the injection well at the standard injection rates (e.g., 1,250 L/h for 24 h).
18) Restart production at the production wells.
It should be noted that total well treatment period does not exceed the breakthrough times between any well pairing.

Claims

1. A method for treatment of a subterranean target site comprising the steps of:

a) determining fluid flow patterns of injection fluid between an injection well and one or more production wells in the subterranean site;

b) injecting a well treatment fluid in the subterranean site; and

c) controlling the distribution of the well treatment fluid amongst the production wells,

wherein oil recovery is improved.

2. The method of claim 1 wherein determining fluid flow patterns of injection fluid is by reservoir modeling, tracer testing, or approximation methods,

3. The method of claim 1 wherein controlling the distribution of the well treatment fluid is by selective shut off or flow restriction of one or more production wells.

4. The method of claim 1 wherein the well treatment fluid is selected from the group consisting of a chemical treatment fluid, a polymer fluid, a surfactant fluid, a high pH fluid, a low salt fluid, and combinations thereof.

5. The method of claim 4 wherein the chemical well treatment fluid is a nutritional chemical fluid for feeding native microorganisms in said subterranean target site.

6. The method of claim 4 wherein the chemical treatment fluid is a suspension of exogenous microorganisms in a nutritional chemical fluid.

7. The method of claim 4 wherein said polymer fluid consists of carboxymethylcellulose, hydroxyethylcellulose, carboxymethylhydroxyethyl-cellulose, guar gum, hydroxypropyl guar. carboxymethylhydroxypropyl guar, polyacrylamide, polyamines, xanthan, polysaccharides or polyvinyl-alcohol derivatives, or a combination therefrom.

8. The method of claim 4 wherein said surfactant consists of anionic sulfonates, nonionics (ethylene oxide derivatives), quaternary ammonium compounds, fluorosurfactants, amphoterics or glycol ethers, or a combination therefrom.

9. The method of claim 4 wherein said high pH fluid comprises a material with a pKa greater than 10, wherein the material consists of sodium silicate, sodium hydroxide or sodium carbonate, or a combination therefrom.

10. The method of claim 6 wherein the exogenous microorganisms comprise one or more species of: Pseudomonas, Bacillus, Actinomycetes, Acinetobacter, Arthrobacter, Schizomycetes, Corynebacteria, Achromobacteria, Arcobacter, Enterobacteria, Nocardia, Saccharomycetes, Schizosaccharomyces, Vibrio, Shewanella, Thauera, Petrotoga, Microbulbifer, Marinobacteria, Fusibacteria, and Rhodotorula.

11. The method of claim 4 wherein a combination of polymer, surfactant, and high pH fluids is used together.

12. The method of claim 4 wherein polymer, surfactant and high pH fluids are used in sequence.