Wells – Processes – Separate steps of fracturing or attacking formation
Reexamination Certificate
2001-02-12
2002-05-28
Suchfield, George (Department: 3672)
Wells
Processes
Separate steps of fracturing or attacking formation
C166S055100, C166S120000, C166S135000, C166S177500, C166S191000, C166S297000, C166S308400, C166S384000, C166S385000, C166S386000
Reexamination Certificate
active
06394184
ABSTRACT:
FIELD OF THE INVENTION
This invention relates generally to the field of perforating and treating subterranean formations to increase the production of oil and gas therefrom. More specifically, the invention provides an apparatus and a method for perforating and treating multiple intervals without the necessity of removing equipment from the wellbore between steps or stages.
BACKGROUND OF THE INVENTION
When a hydrocarbon-bearing, subterranean reservoir formation does not have enough permeability or flow capacity for the hydrocarbons to flow to the surface in economic quantities or at optimum rates, hydraulic fracturing or chemical (usually acid) stimulation is often used to increase the flow capacity. A wellbore penetrating a subterranean formation typically consists of a metal pipe (casing) cemented into the original drill hole. Holes perforations) are placed to penetrate through the casing and the cement sheath surrounding the casing to allow hydrocarbon flow into the wellbore and, if necessary, to allow treatment fluids to flow from the wellbore into the formation.
Hydraulic fracturing consists of injecting fluids (usually viscous shear thinning, non-Newtonian gels or emulsions) into a formation at such high pressures and rates that the reservoir rock fails and forms a plane, typically vertical, fracture (or fracture network) much like the fracture that extends through a wooden log as a wedge is driven into it. Granular proppant material, such as sand, ceramic beads, or other materials, is generally injected with the later portion of the fracturing fluid to hold the fracture(s) open after the pressure is released. Increased flow capacity from the reservoir results from the easier flow path left between grains of the proppant material within the fracture(s). In chemical stimulation treatments, flow capacity is improved by dissolving materials in the formation or otherwise changing formation properties.
Application of hydraulic fracturing as described above is a routine part of petroleum industry operations as applied to individual target zones of up to about 60 meters (200 feet) of gross, vertical thickness of subterranean formation. When there are multiple or layered reservoirs to be hydraulically fractured, or a very thick hydrocarbon-bearing formation (over about 60 meters), then alternate treatment techniques are required to obtain treatment of the entire target zone. The methods for improving treatment coverage are commonly known as “diversion” methods in petroleum industry terminology.
When multiple hydrocarbon-bearing zones are stimulated by hydraulic fracturing or chemical stimulation treatments, economic and technical gains are realized by injecting multiple treatment stages that can be diverted (or separated) by various means, including mechanical devices such as bridge plugs, packers, downhole valves, sliding sleeves, and baffle/plug combinations; ball sealers; particulates such as sand, ceramic material, proppant, salt, waxes, resins, or other compounds; or by alternative fluid systems such as viscosified fluids, gelled fluids, foams, or other chemically formulated fluids; or using limited entry methods. These and all other methods and devices for temporarily blocking the flow of fluids into or out of a given set of perforations will be referred to herein as “diversion agents.”
In mechanical bridge plug diversion, for example, the deepest interval is first perforated and fracture stimulated, then the interval is typically isolated by a wireline-set bridge plug, and the process is repeated in the next interval up. Assuming ten target perforation intervals, treating 300 meters (1,000 feet) of formation in this manner would typically require ten jobs over a time interval of ten days to two weeks with not only multiple fracture treatments, but also multiple perforating and bridge plug running operations. At the end of the treatment process, a wellbore clean-out operation would be required to remove the bridge plugs and put the well on production. The major advantage of using bridge plugs or other mechanical diversion agents is high confidence that the entire target zone is treated. The major disadvantages are the high cost of treatment resulting from multiple trips into and out of the wellbore and the risk of complications resulting from so many operations in the well. For example, a bridge plug can become stuck in the casing and need to be drilled out at great expense. A further disadvantage is that the required wellbore clean-out operation may damage some of the successfully fractured intervals.
One alternative to using bridge plugs is filling the portion of wellbore associated with the just fractured interval with fracturing sand, commonly referred to as the Pine Island technique. The sand column in the wellbore essentially plugs off the already fractured interval and allows the next interval to be perforated and fractured independently. The primary advantage is elimination of the problems and risks associated with bridge plugs. The disadvantages are that the sand plug does not give a perfect hydraulic seal and it can be difficult to remove from the wellbore at the end of all the fracture stimulations. Unless the well's fluid production is strong enough to carry the sand from the wellbore, the well may still need to be cleaned out with a work-over rig or coiled tubing unit. As before, additional wellbore operations increase costs, mechanical risks, and risks of damage to the fractured intervals.
Another method of diversion involves the use of particulate materials, granular solids that are placed in the treating fluid to aid diversion. As the fluid is pumped, and the particulates enter the perforations, a temporary block forms in the zone accepting the fluid if a sufficiently high concentration of particulates is deployed in the flow stream. The flow restriction then diverts fluid to the other zones. After the treatment, the particulate is removed by produced formation fluids or by injected wash fluid, either by fluid transport or by dissolution. Commonly available particulate diverter materials include benzoic acid, napthalene, rock salt (sodium chloride), resin materials, waxes, and polymers. Alternatively, sand, proppant, and ceramic materials, could be used as particulate diverters. Other specialty particulates can be designed to precipitate and form during the treatment.
Another method for diverting involves using viscosified fluids, viscous gels, or foams as diverting agents. This method involves pumping the diverting fluid across and/or into the perforated interval. These fluid systems are formulated to temporarily obstruct flow to the perforations due to viscosity or formation relative permeability decreases; and are also designed so that at the desired time, the fluid system breaks down, degrades, or dissolves (with or without adding chemicals or other additives to trigger such breakdown or dissolution) such that flow can be restored to or from the perforations. These fluid systems can be used for diversion of matrix chemical stimulation treatments and fracture treatments. Particulate diverters and/or ball sealers are sometimes incorporated into these fluid systems in efforts to enhance diversion.
Another possible process is limited entry diversion in which the entire target zone of the formation to be treated is perforated with a very small number of perforations, generally of small diameter, so that the pressure loss across those perforations during pumping promotes a high, internal wellbore pressure. The internal wellbore pressure is designed to be high enough to cause all of the perforated intervals to fracture simultaneously. If the pressure were too low, only the weakest portions of the formation would fracture. The primary advantage of limited entry diversion is that there are no inside-the-casing obstructions like bridge plugs or sand to cause problems later. The disadvantage is that limited entry fracturing often does not work well for thick intervals because the resulting fracture is frequently too narrow (the proppant cannot all be pumped
Carlson Lawrence O.
Goss Glenn S.
Kinison David A.
Nygaard Kris J.
Shafer Lee L.
ExxonMobil Upstream Research Company
Suchfield George
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