Wells – Processes – Cyclic injection then production of a single well
Reexamination Certificate
2001-12-14
2003-06-24
Suchfield, George (Department: 3672)
Wells
Processes
Cyclic injection then production of a single well
C166S279000, C166S310000, C166S312000, C507S266000, C507S902000
Reexamination Certificate
active
06581687
ABSTRACT:
This invention relates to water in oil microemulsions and, in particular, to the use of water in oil microemulsions to deploy water soluble or water dispersible oil field or gas field production chemicals.
BACKGROUND OF THE INVENTION
Among oil field chemicals are scale inhibitors, which are used in production wells to stop scaling in the rock formation and/or in the production lines downhole and at the surface. Scaling not only causes a restriction in pore size in the rock formation matrix (also known as ‘formation damage’) and hence reduction in the rate of oil and/or gas production but also blockage of tubular and pipe equipment during surface processing. To overcome this, the production well is subjected to a so called “shut-in” treatment whereby conventionally an aqueous composition comprising a scale inhibitor is injected into the production well, usually under pressure, and “squeezed” into the formation and held there. In the squeeze procedure, scale inhibitor is injected several feet radially into the production well where it is retained by adsorption and/or formation of a sparingly soluble precipitate. The inhibitor slowly leaches into the produced water over a period of time and protects the well from scale deposition. The “shut-in” treatment needs to be done regularly e.g. one or more times a year at least if high production rates are to be maintained and constitutes the “down time” when no production takes place. Over the year there is a reduction in total production corresponding to the number of down times during the squeeze/shut-in operation, as well as reduced production as the scaling problem builds up. However, in some instances the scale inhibitor is poorly retained within the reservoir rock matrix and short squeeze lifetimes are experienced. The net result in these cases is frequent well interventions which impact on both well productivity and field profitability. It is also possible to “squeeze” corrosion inhibitors to protect the production tubing of the well bore against corrosion or asphaltene inhibitors to control precipitation of asphaltenes in the rock formation and in the production tubing. It would therefore be desirable to provide an improved method of deploying these inhibitors.
DESCRIPTION OF THE INVENTION
We have now discovered a means for and a method of increasing the effectiveness of oil field or gas field production chemicals, in particular scale inhibitors, thereby allowing a decrease in-the frequency of squeeze/shut in operations and an increase in the oil/gas production rate.
The present invention relates to a microemulsion comprising (i) an oil phase, (ii) an aqueous phase comprising an aqueous solution of a water soluble oil field or gas field production chemical or an aqueous dispersion of a water dispersible oil field or gas field production chemical and (ii) at least one surfactant, wherein the aqueous phase is distributed in the oil phase in the form of droplets having a diameter in the range 1 to 1000 nm or in the form of microdomains having at least one dimension of length, breadth or thickness in the range 1 to 1000 nm.
An advantage of using a water in oil microemulsion for deploying water soluble or water dispersible oil field or gas field production chemicals as opposed to employing a conventional aqueous composition of the production chemical is that the amount of water pumped into the reservoir is minimised. This is important for wells containing low levels of water (less than 1% water) since injecting water into the well reduces the relative permeability of the oil and increases the relative permeability of the water. Until the amount of water in the formation near the well bore is reduced to pre-squeeze levels the productivity of the well will be lower than its pre-squeeze productivity. The use of a microemulsion having a continuous oil phase also has advantages for water-sensitive oil or gas reservoirs. In a water-sensitive oil or gas reservoir, clays may swell in the presence of water and/or water may become trapped, thereby preventing or reducing oil flow. Also, reducing the amount of water pumped into a reservoir having a sandstone rock formation minimises the production of sand which occurs when water dissolves the carbonate cements that consolidate the sandstone. A further advantage of deploying a production chemical using a water in oil microemulsion is that aqueous solutions of certain production chemicals (e.g. scale inhibitors) are fairly acidic and can increase the rate of dissolution of the carbonate cements. By encapsulating such acidic aqueous solutions in an oil, damage to the formation close to the wellbore can be eliminated or at least mitigated. Also, some wells are poorly pressure supported (low reservoir pressure) and are incapable of “lifting” a column of water out of the well. Conventionally, nitrogen gas lift is used to raise the column of water but this can be very expensive. By employing a water in oil microemulsion having an oil phase which is less dense than water, a column of the microemulsion can be lifted out of the well at a lower pressure than required for a column of water. The most significant advantage is that deploying a production chemical in a water in oil microemulsion increases the effectiveness of the production chemical by reducing the number of squeezing and shut-in operations. This is because “encapsulation” or protection of the oil field chemical within the oil continuous phase places the production chemical deeper into the rock formation (near well bore region) and the low interfacial tension of the microemulsion acts to remove oil from the surfaces of the porous rock formation thereby exposing more surface area for the production chemical to absorb or precipitate onto.
Microemulsions in general are known, see, for example “Microemulsions”, Editor I D Robb, Plenum Press, New York, 1982 which is herein incorporated by reference. They differ from ordinary emulsions in having droplets of very small size or in having microdomains having at least one dimension of length, breadth or thickness of very small size. Thus, microemulsions appear clear to the naked eye or even the optical microscope, compared to the larger droplets (greater than 1000 nm diameter) of conventional cloudy emulsions.
Where the aqueous phase is distributed in the oil phase in the form of droplets, the droplets preferably have an average diameter in the range of 10 to 500 nm, more preferably 50 to 250 nm. The droplet size distribution is generally such that at least 90% of the diameters are within 20% or especially 10% of the average diameter. The microemulsions are transparent to the eye and are apparently isotropic.
Where the aqueous phase is distributed in the oil phase in the form of microdomains, the microdomains preferably have at least one dimension of length, breadth or thickness in the range 10 to 500 nm, more preferably 50 to 250 nm.
The oil phase is essentially any liquid which is immiscible with the aqueous phase. For example the oil phase may be selected from the group consisting of liquid alkanes (preferably C
5
-C
20
alkanes, more preferably C
8
to C
15
alkanes, most preferably C9-C
12
alkanes, for example, n-nonane, n-decane, and n-undecane), liquid alkyl halides (for example, carbon tetrachloride or dichloromethane) and liquid aromatic hydrocarbons (for example, toluene and xylene). The oil phase may also be a paraffin oil, a natural oil, diesel, kerosene, gas oil, crude oil, base oil, liquid carbon dioxide, liquid chlorofluorocarbons such as CCl
2
F
2
, CHCl
2
F and CH
3
CClF
2
(known as freons), tetrahydrofuran, dimethyl formamide and dimethyl sulphoxide.
The aqueous phase in the microemulsion may comprise fresh, tap, river, sea, produced or formation water. The aqueous phase may have a total salinity of 0-250 g/l, for example 5-50 g/l. The aqueous phase may have a pH of 0.5-9. Where the aqueous phase comprises a sea-water solution of a highly acidic production chemical such as, for example, a scale inhibitor, the aqueous phase usually has a highly acidic pH of 0.1-1. In such cases it may
Collins Ian Ralph
Vervoort Isabelle
BP Exploration Operating Company Limited
Nixon & Vanderhye
Suchfield George
LandOfFree
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