Earth boring – well treating – and oil field chemistry – Well treating – Contains organic component
Reexamination Certificate
2000-06-16
2004-12-07
Tucker, Philip C. (Department: 1712)
Earth boring, well treating, and oil field chemistry
Well treating
Contains organic component
C507S259000, C507S122000, C516S058000
Reexamination Certificate
active
06828281
ABSTRACT:
FIELD OF THE INVENTION
The present invention involves surfactant flooding for the recovery of hydrocarbon oils in which synthetic polyisobutylene sulfonates are employed in an alkaline aqueous media in conjunction with at least one other surfactant or co-surfactants, preferably a sulfonate, an alcohols or a nonionic surfactant, or some mixture thereof, to lower the interfacial tension between the surfactant solution and the hydrocarbon oil, i.e. crude oil, that is to be recovered from a subterranean reservoir. The aqueous surfactant solutions thus allow for enhanced recovery of crude oil from subterranean reservoirs.
BACKGROUND OF THE INVENTION
Crude oil, i.e. hydrocarbons, which accumulate in and are produced from subterranean reservoirs, are recovered or produced through one or more wells drilled into the reservoir. Prior to producing the crude oil, the formation, a porous media, is saturated with crude oil and all the pores are filled with crude oil. The initial recovery of the hydrocarbons is generally accomplished by “primary recovery” techniques wherein only the natural forces present in the reservoir are utilized to produce the oil. In this primary recovery, only a portion of the crude oil is driven out of the pores by formation pressure. For instance, a usual condition upon depletion of the natural forces and the termination of primary recovery is that a rather large portion of the crude oil, typically more than half its original volume, remains trapped within the reservoir. Moreover, many reservoirs lack sufficient natural forces even to produce the oil by primary methods.
This phenomenon has long been known in the petroleum industry, and consequently, recognition of such a fact has led to the development and use of many enhanced oil recovery techniques. Most of these techniques involve injection of at least one fluid or gas into the subterranean reservoir to produce an additional amount of crude oil. These liquids include water, steam, a miscible gas such as CO
2
or natural gas, or an immiscible gas such as nitrogen.
While other fluids can provide higher oil recovery, water is the most widely used and economical fluid of choice. Water flooding involves the injection of water into an oil-bearing reservoir. As the water moves through the reservoir, it acts to displace the oil therein to a production system composed of one or more wells through which the oil is recovered. Nevertheless water does not displace oil with high efficiency because of the immiscibility of water and oil and because of the high interfacial tension between them.
It has long been recognized that this high interfacial tension existing between the injected water and the reservoir oil, the relative mobilities of the reservoir oil and injected water, and the wettability characteristics of the rock surfaces within the reservoir are factors which can negatively influence the amount of oil recovered by water flooding.
There are two principal mechanisms of enhancing the oil recovery of an injected fluid. These methods are increasing volumetric sweep efficiency of the injected fluid and increasing the oil displacement efficiency by the injected fluid. Both techniques involve the addition of chemicals which modify the properties of the injected fluid.
A very usefull technique for increasing the oil recovery of water has been to add surfactants to the flood water in order to effectively lower the oil/water interfacial tension and/or alter the wettability characteristics of the reservoir rock. This effective reduction in interfacial tension allows the deformation of crude oil droplets thereby improving the movement of the oil through the porous channels of the reservoir. Therefore, with the addition of the surfactants to the flood water, the interfacial tension is effectively reduced between the water and the reservoir oil, the oil droplets deform, coalesce and subsequently flow with the flood water toward the producing wells. It is generally accepted that the interfacial tension between the surfactant solution and the reservoir oil should be reduced to less than 0.1 dyne/cm for low-tension flooding to give effective recovery. In order to provide oil recovery that is effective and economically feasible, the goal is to reduce interfacial tension to 10
−3
dynes/cm.
Generally, these methods of surfactant flooding which employ the injection of flood water to which has been added one or more surface active agents or surfactants, into a reservoir and allowing the solution or emulsion of surfactants to sweep through the formation and displace or recover oil, are commonly referred to as surfactant water flooding or as low tension water flooding, the latter term having reference to the mechanism involving the reduction of the oil-water interfacial tension. This procedure may be followed by a polymer solution for mobility control and improved sweep efficiency.
Anionic surfactants are popularly utilized in such water flooding applications. For example, a paper by W. R. Foster entitled “A Low-Tension Water flooding Process”,
Journal of Petroleum Technology
, Vol. 25, February 1973, pp. 205-210, describes a technique involving the injection of an aqueous solution of petroleum sulfonates within designated equivalent weight ranges and under controlled conditions of salinity.
One problem encountered in water-flooding with anionic surfactants, and with petroleum sulfonates in particular, is that they tend to become depleted from the injected solution through precipitation as the solution moves through the reservoir. The surfactants tend to be lost as insoluble salts of ionic materials, such as polyvalent metal ions. This phenomenon, referred to as a lack of stability, is more often seen in so-called “hard water” or “high brine” environments. High brine waters typically contain high concentrations of inorganic salts, generally over 2% NaCl, for instance, and over 0.5% CaCl
2
and MgCl
2
total. Indeed, some “high brine” reservoirs may have concentrations of NaCl of over 4%, and concentrations of over 2% CaCl
2
and MgCl
2
combined. In particular, these surfactants tend to precipitate from solution in the presence of monovalent salts such as sodium chloride at relatively low concentrations in excess of about 2 to 3 weight percent, or in the presence of even lower concentrations of divalent metal ions such as calcium and magnesium ions. For example, divalent metal ion concentrations of about 50-100 ppm and above usually tend to cause precipitation of the petroleum sulfonates. Other depletion may be caused by the adsorption of the surface active agent on the rock surface of the reservoir, or by the physical entrapment of the petroleum sulfonates in the pore spaces of the rock matrix.
In any case, it is quite obvious that if the surface active agent is removed from the water flood solution as it moves through the reservoir, the agent is not available to decrease the interfacial tension at the oil/water interface, and quite naturally it would follow that the surfactant depletion reduces oil recovery efficiency.
In a surfactant flood oil recovery process where the water contains a surfactant, the efficiency of the oil recovery from the reservoir is strongly affected by (1) the rate of surfactant loss, or surfactant stability, and (2) the surface activity of the surfactant, or in other words, the extent to which the interfacial tension is lowered at the oil/water interface. The lower the interfacial tension, the more efficient the recovery.
The tendency of surfactantants, and in particular of petroleum sulfonates to be depleted from the injected solution, also referred to as a lack of stability, has long been recognized in the art as a problem. Many suggestions have been proposed to overcome such problems. For instance, U.S. Pat. No. 3,637,017, Gale et al. describes a process which employs sodium petroleum sulfonate surfactants having average molecular weights within the range of 465-480 and alcohols, including aliphatic alcohols from 1 to 8 carbon atoms. In the method described in Gale et al., an aqueous solution of a petr
Feuerbacher Dave
Hou Wangqi
Akzo Nobel Surface Chemistry LLC
Mancini Ralph J.
Tucker Philip C.
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