Earth boring – well treating – and oil field chemistry – Well treating – Contains organic component
Utility Patent
1997-06-05
2001-01-02
Tucker, Philip (Department: 1712)
Earth boring, well treating, and oil field chemistry
Well treating
Contains organic component
C507S224000, C507S225000, C507S903000, C507S922000, C507S924000, C166S308400
Utility Patent
active
06169058
ABSTRACT:
BACKGROUND OF THE INVENTION
1. Field of the Invention
This invention relates generally to subterranean formation treatments and, more specifically, to hydraulic fracturing treatments for subterranean formations. In particular, this invention relates to the addition of hydrophillic swelling polymers to hydrocarbon-based fracture treatment fluids to control fluid loss during a hydraulic fracture treatment. This invention also relates to the addition of swelling polymers to hydrocarbon-based fracture treatment fluids to prevent or inhibit fracture growth into adjacent water-bearing formations and prevent or inhibit water production from these formations following a hydraulic fracture treatment.
2. Description of Related Art
Hydraulic fracturing of oil or gas wells is a technique routinely used to improve or stimulate the recovery of hydrocarbons. Hydraulic fracturing is typically employed to stimulate wells which produce from low permeability formations. In such wells, recovery efficiency is typically limited by the flow mechanisms associated with a low permeability formation. Hydraulic fracturing is usually accomplished by introducing a proppant-laden treatment fluid into a producing interval at high pressures. This fluid induces a fracture in the reservoir and transports proppant into the fracture, before “leaking off” into the surrounding formation. After the treatment, proppant remains in the fracture in the form of a permeable “pack” that serves to “prop” the fracture open. In this way, the proppant pack forms a highly conductive pathway for hydrocarbons and/or other formation fluids to flow into the wellbore.
Typically, viscous gels or foams are employed as fracturing fluids in order to provide a medium that will adequately suspend and transport solid proppant materials, as well as to impair loss of fracture fluid to the formation during treatment (commonly referred to as “filterability” or “fluid loss”). As such, viscosity of a fracture fluid may affect fracture geometry because fluid loss affects the efficiency of a treatment. For example, when the rate of fluid loss to the formation equals or exceeds the rate of injection or introduction of fluid into a fracture, the fracture stops growing. Conversely, when the rate of fluid loss is less than the injection or introduction rate, taken together with other factors, a fracture continues to propagate. Excessive fluid loss thus results in fractures that are smaller and shorter than desired.
Viscosity of commercially available hydrocarbon-based gels typically results from a mixture of alkylphosphate esters and aluminum or ferric ions in an acidic environment. When the acidity of such a mixture is adjusted to the optimum level, the surfactants tend to organize themselves from sphere-like micelles to rod-like micelles. Micelle size is typically dependent on concentrations of alkylphosphate ester and metallic ions together with the relative ratios of mono-, di- and tri-phosphate esters. Viscosities in excess of about 400 cps at 170 sec
−1
, as measured by a Fann 50C viscometer, are routinely measured for these fluids. As a rule, viscosities in excess of about 100 cps are regarded as satisfactory for fracturing. Such mixtures of esters and metal salts form micelles with associations that are relatively weak and lack sufficient filter cake building ability to effectively control fluid loss. Further information may be found in “Developments in Hydrocarbon Fluids for High Temperature Fracturing,” by Burnham et al.,
SPE
7564.
In order to limit fluid loss and improve fracture efficiency, viscosifying agents are often added to fracturing fluids. In the case of water-based fracturing fluids, polymers such as guar, derivatized guar or derivatized celluloses are typically employed to viscosity the fluid. These polymers are typically added to water or dilute saline solutions at concentrations ranging from about 10 lbs. to about 60 lbs. per 1000 gallons of treating fluid (or from about 0.24% to about 0.72% (wt/vol)) to hydrate the polymers. These polymers may also be crosslinked or foamed to achieve three dimensional gels and further increases in viscosity. Under filtering conditions like those occurring during fluid loss to a subterranean formation, crosslinked polymers tend to filter out, leaving a layer of collapsed polymer chains on the filtering media that is referred to as the filter cake. As filtering continues, the cake tends to grow and impair solvent loss through the filter cake membrane. Therefore, during a hydraulic fracturing treatment, hydrophillic polymers tend to form filter cake walls on a formation face, thereby inhibiting fluid loss to the formation.
However, for hydrocarbon-based fracture gels, these types of hydrophillic polymers are typically not effective viscosifiers due to insufficient water content in the fracture fluid. Therefore, hydrocarbon-based gels are typically viscosified by associating surfactants. Forces binding the associating surfactants together are typically ionic in nature. Although these forces can be strong in the absence of solvents, polar solvents present in micelles allow the surfactants to continually associate and disassociate. When mechanical forces (such as filtration) are applied, these surfactants tend to readily disassociate to relieve those forces acting on the micelle structure. In the case of well treatments, this phenomenon hampers fluid loss control by inhibiting filter cake formation. Small counter ions, such as hydronium, sodium, chloride, sulfate and acetate ions tend to maintain charge balance of these disassociated surfactants. Because surfactants lack the filter cake building properties of hydrophillic polymers, fluid loss is difficult to control during fracture treatments using hydrocarbon-based fluids.
In an attempt to control fluid loss during hydrocarbon-based fracture treatments, starch or similar carbohydrate polymers have been added to hydrocarbon-based gels. Typically, these polysaccharide-based fluid loss additives are added as dry powders or hydrocarbon-based suspensions. However, due to the small amount of water (if any) usually present in such gels, these materials typically fail to provide the degree of fluid loss control obtainable with water-based fracturing fluids especially at higher temperatures. A further disadvantage with such natural polymer fluid loss control agents is that relatively large volumes (typically from about 10 to about 50 lbs. per thousand gallons of treatment fluid) of these materials are usually required to achieve even marginal fluid loss control. These polymer additives, when in an unhydrated state, do not readily deform under mechanical shear. Consequently, as a fluid loss additive, they tend to bridge together at flow channels in the rock. Due to this lack of deformation, the concentration of additive may exceed 40 lbs. per thousand gallons of treatment fluid before suitable fluid loss control is observed depending on permeability of the formation. Such large volumes may be damaging to a fracture proppant pack and/or formation. Moreover, the pH of any water phase present in a hydrocarbon-based fracture treatment is typically acidic (typically between about 2 and about 3) due to addition of viscosifying agents. This acidic environment tends to accelerate breakdown of natural polymers such as carbohydrates, thereby further reducing their effectiveness as fluid loss control agents.
Other fluid loss control methods utilize solid materials, such as 100 mesh sand or 200 mesh sand (commonly referred to as silica flour) and clay to control fluid loss during hydrocarbon-based fracture treatments. However, the use of solid plugging materials is undesirable because of their low efficiency as fluid loss additives and because they tend to cause unremovable damage to the proppant pack. Silica flour is often added to fracturing fluids in amounts from about 25 lbs. to about 100 lbs. per 1,000 gallons of treating fluid. The silica flour is often produced back through the propped fracture, which in turn can cause damage to the operation of downhole
Dawson Jeffrey C.
Kesavan Subramanian
Le Hoang V.
Mack David J.
Nelson Scott G.
BJ Services Company
O'Keefe Egan & Peterman, LLP
Tucker Philip
LandOfFree
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