Earth boring – well treating – and oil field chemistry – Well treating – Contains intended gaseous phase at entry into wellbore
Reexamination Certificate
2000-05-02
2003-10-14
Tucker, Philip (Department: 1712)
Earth boring, well treating, and oil field chemistry
Well treating
Contains intended gaseous phase at entry into wellbore
C516S013000
Reexamination Certificate
active
06632778
ABSTRACT:
TECHNICAL FIELD OF THE INVENTION
This Invention relates to the consolidation of hydrocarbon-bearing rock formations to minimize flow of particulates into a wellbore, and in particular to fluids and methods for consolidation of formations comprising at least two layers which differ in permeability.
BACKGROUND OF THE INVENTION
Hydrocarbons (oil, natural gas, etc.) are obtained from a subterranean geologic formation (i.e., a “reservoir”) by drilling a well that penetrates the hydrocarbon-bearing formation. This provides a partial flowpath for the hydrocarbon to reach the surface. In order for the hydrocarbon to be “produced,” that is travel from the formation to the wellbore (and ultimately to the surface), there must be a sufficiently unimpeded flowpath from the formation to the wellbore. This flowpath is through the formation rock—e.g., sandstone, carbonates—which has pores of sufficient size, connectivity, and number to provide a conduit for the hydrocarbon to move through the formation.
When hydrocarbon is produced from a well, small particulates present in the formation may travel with the hydrocarbon from the formation, through the wellbore, to the surface. The presence of small particulates is especially likely in soft formations comprising sand, sandstone, or limestone. The travel of small particulates with the hydrocarbon is undesirable. Small particulates flowing through the wellbore will erode equipment in the wellbore and at the surface, which can make replacement of such equipment necessary. Small particulates in the produced hydrocarbon must also be removed before the hydrocarbon can be processed. Also, small particulates can come to reside in the wellbore to the point where hydrocarbon production is greatly diminished or completely stopped.
One approach to minimize flow of small particulates into the wellbore is by the use of a gravel pack. A screen is placed around the wellbore casing. To the outside of the screen and around the screened wellbore casing is placed a gravel pack. As hydrocarbons are produced from the formation, they travel through the gravel pack and the screen before entering the wellbore. The gravel pack and screen inhibit the flow of small particulates but, under normal conditions, do not substantially inhibit the production of hydrocarbons. However, placing a gravel pack and screen requires specialized equipment, and the gravel pack and screen create a mechanical restriction which may be plugged by scale or may be eroded by the flow of small particulates. It is desirable to have a method for completing wells in unconsolidated formations that does not involve the use of a gravel pack and screen.
Another approach involves consolidating the formation by injecting a fluid comprising a resin or epoxy. Conventional consolidating fluids, such as Sandlock™ (Schlumberger), comprise a resin, and optionally a curing agent, a catalyst, and an oil wetting agent. When injected into the formation, the resin (acted upon by the curing agent and catalyst, if present) sets, causing consolidation of the formation and reduction in the concentration of small particulates. Consolidating fluids and methods for their use are reported in U.S. Pat. Nos. 5,806,593; 5,199,492; 4,669,543; 4,427,069; and 4,291,766.
However, conventional fluids have a number of disadvantages. Because the fluids have relatively long setting times, they readily flow into regions of the formation which have already received a sufficient amount of the fluid (passage of least resistance). As a result, the length of wellbore that can be treated in a single application is limited to less than about 40 feet (10 m).
Also, a disadvantage is seen in consolidation of heterogeneous formations, e.g. formations which comprise at least a first layer and a second layer, wherein the first layer has a greater permeability than the second layer (e.g. the ratio of the permeability of the first layer to the permeability of the second layer, which may herein be termed the “permeability ratio,” is greater than 1). The greater permeability of the first layer allows the consolidating fluid to more readily penetrate the first layer. As a result, after the consolidating fluid enters the formation and sets, the first layer is highly consolidated, but the second layer is consolidated only to a very minor extent, if at all.
Therefore, if a formation is heterogeneous, e.g. the formation comprises at least a first layer and a second layer, a need exists for consolidating fluids that are capable of consolidating both the first layer and the second layer in a single application. Preferably, such consolidating fluids are “self-diverting,” as defined below.
A number of well treatment fluids, including consolidating fluids, comprising either an emulsion or a foam are known. U.S. Pat. No. 5,363,917 teaches a foamed consolidating fluid which can support combustion of hydrocarbons in the formation. Products of the hydrocarbon combustion consolidate the formation.
U.S. Pat. Nos. 5,010,953 and 5,567,088 disclose a consolidating fluid provided as an aerosol in steam. The former patent teaches that steam maintains void spaces in the formation during setting of a polymerizable compound, e.g. furfuryl alcohol.
Published PCT application WO 98/53180 teaches emulsions comprising at least two discontinuous phases comprising a gelling polymer, such as a polysaccharide, in one phase and an inorganic or organic crosslinker in another.
Great Britain Patent No. 2 022 653 teaches water-in-oil-in-water emulsions for matrix acidizing operations. In one teaching, particles are present in the internal water phase and the acid is present in the external water phase. In use, the particles plug pore spaces in the formation and divert acid to other regions of the formation. In another teaching, the acid is present in the internal water phase, which in use will strip out in narrow pore throats where acidizing is most effective.
SUMMARY OF THE INVENTION
The present invention relates to the use of self-diverting fluids in consolidating operations. As used herein, the term “diverting” means that, in a subterranean formation comprising at least a first layer and a second layer, wherein the first layer has a higher permeability than the second layer, sand production from the formation will be less than when a conventional, non-diverting fluid is used. Though not to be bound by theory, it is believed that the depth to which the self-diverting fluid enters the second layer will be greater than that predicted from the permeability ratio. For an example, if the permeability ratio is 4:1, an observation of reduced sand production occurs presumably if the depth of penetration in the second layer is greater than 20% of that in the first layer. “Self-diverting” means that the diversion is a property of the consolidating fluid itself, and no additional fluid or procedure is required to achieve it.
Preferably, self-diversion leads to a reduction in sand production of at least about 10% relative to known consolidating fluids, more preferably at least about 20%, most preferably at least about 30%. The upper limit on reduction of sand production would be reached when, presumably, depth of penetration is substantially equal in each layer of the formation, and would be observed as very little sand production from the formation.
The self-diversion can be obtained by structuring the fluid by incorporation of another phase, either liquid or gas. Also, additives can be used to prevent at least one of the active ingredients of the consolidating fluid from interacting with the other active ingredients until the fluid is forced into the porous medium, at which point consolidation and reduction of the formation mobility occurs simultaneously. However self-diversion is brought about, the result is increased resistance for continuing fluid flow into the area treated, and consequent divergence of flow into other layers of the formation which are then treated adequately.
In most embodiments, the present invention is directed to a consolidating fluid comprising a resin, a curing agent, and
Ayoub Joseph A.
Crawshaw John P.
Way Paul W.
Jeffery Brigitte
Menes Catherine
Schlather Stephen
Schlumberger Technology Corporation
Tucker Philip
LandOfFree
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