The use of aqueous stabilized nanoparticle dispersions (NPDs) with 4-20 nm silicon dioxide particles has been demonstrated in both experimental laboratory evaluations and field trials to provide production improvements in wellbore remediation and increased injectivity over conventional treatments. To date over 50 successful beta test applications have been performed. Additional work is under way to develop improved NPD formulations that will enable applications in areas like hydraulic fracturing, acidizing, production chemicals, water flooding, tar sands, and heavy oil. Nanofluids are stable colloidal dispersions or micellar dispersions that accelerate recovery of hydrocarbon from oil and gas reservoirs by the use of the unique enabling mechanism of disjoining pressure. The nanoparticles in NPD utilize this mechanism to form a self-assembled wedge-shaped film on contact with a discontinuous phase. This wedge film acts to separate formation fluids (oil, paraffin, water, and/or gas) from the formation's surface, thereby recovering more fluids than previously possible with conventional additives or fluids. This paper will present a description of the disjoining pressure mechanism and present Research laboratory and actual field treatment beta testing to illustrate that higher fluid recoveries and injection rates can be achieved, by enabling conventional intervention fluids to function more efficiently.
A series of hydraulic fracturing injection experiments was performed in unconsolidated sand in a radial flow cell (RFC) to delineate the fundamental mechanisms controlling fracture propagation. The results of this work will be used to optimize the current fracpacking practices in unconsolidated and poorly consolidated sand and to develop adequate modeling techniques. Although the generic word "fracture" is used throughout this document and elsewhere to describe injection-induced formation parting during stimulation, it will be made clear that the tip propagation mechanisms in unconsolidated sand are fundamentally different from linear elastic fracture mechanics (LEFM) as defined for competent rocks. Conceptually, the RFC used for the injection tests simulates a 1-ft thick section of unconsolidated sand formation within a 3-ft radius of a wellbore. The tests in this system included injection of cross-linked guar and visco-elastic surfactant into 3,000 md sand samples subjected to different overburden stresses. The following is a summary of the findings:The experimental data suggest that "fracture" propagation in unconsolidated sand is primarily a result of shear failure in a process-zone ahead of the fracture tip. The shear failure is caused by large tip stresses (due to tip plasticity) and by pore pressure increase within the process zone.Uncharacteristically large net fracturing pressures (NFP) were encountered for low-efficiency fluids. Generally, the NFP increased with decreasing fluid efficiency.Multiple sub-parallel fracturing and complex fracture geometry was encountered. sub-parallel fractures may be initiated at the tip or at the fracture wall due to shear failure and is dependent on the fluid efficiency and the type of leakoff, i.e., wall building or viscous. The field consequences of sub-parallel fracturing during stimulation may include pre-mature screenout and fracture bridging, short fracture length and extensive formation damage as the fracturing fluid invades the sheared interfaces. Introduction Fracpack completions are frequently performed in poorly consolidated, high-permeability sand formations, such as those in the Gulf of Mexico, to bypass well damage and enhance productivity. Generally, this stimulation involves injecting a small pad of clean fluid, followed by slurry with as much as 15 ppa proppant concentration, depending on the sand carrying capacity of the fluid. As much as 200,000 lbs of sand may be injected in one zone and fracture lengths of over 40 ft may be obtained. Many fracpack designs include tip screenout (TSO) to induce an inflated, highly conductive fracture that is packed by proppant as the fluid leaks off.1,2,3 Depending on the formation properties, a variety of fracturing fluids may be used in a fracpack operation, including borate cross-linked guar, linear gel, VES and non-viscous fluids.4–7 The cross-linked fluids, because of their wall building capability, can create relatively long fractures, but may cause extensive formation damage if the polymer breakdown is incomplete following stimulation. On the other side of the spectrum, non-viscous fluids result in minimal formation damage with the drawback that the resulting fracture is typically very short (less than 5 feet) due to excessive leakoff. These fluids as well as the linear gel and VES must be laden with fluid loss additives to induce effective fractures in high-permeability formations in excess of 500 mD.
The use of stabilized nanoparticle dispersions (NPDs) containing silica particles between 4-20 nm in diameter have been shown to be effective at removing skin damage associated with paraffin blocks, as well as polymer based treating and stimulation fluids. The arrangement of particles at the three phase interface into structural arrays promotes lifting of the damage from the surface, stimulating the reservoir. Aqueous dispersions of nanoparticles used in conjunction with traditional remedial methods can effectively remove damage near the wellbore to be produced out of the well, instead of dissolution and potential displacement of the damage further into the formation. Many of the declining oil fields around the world owe a significant portion of their decreased production to formation damage. Usually, this damage is indicative of naturally occurring blocks, like paraffin, or as a result of intervention processes that occur over the lifetime of a well during drilling, stimulation, or intermittent remediation treatments. Eventually, the well can become damaged to the point it is no longer economically viable. This paper will show lab and field results that indicate aqueous nanoparticle dispersions are a capable, and efficient additive for stimulating a damaged well by removal of skin from the surface of reservoir rock. This effect is due to a unique force called disjoining pressure, which causes particles at the nanometer-scale to force themselves between organic matter and the substrate at the interface of the treating fluid. This force promotes the separation of an organic phase from a rock surface.
TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractMatrix acidizing of carbonate formations has been carried out for many years using HCl acid in various strengths. However, in some high temperature applications, HCl does not produce acceptable stimulation results due to lack of penetration or surface reactions. Organic acids, like formic acid and acetic acid, were introduced to offer a slower reacting a thus deeper stimulating acid. These "retarded" acids also had shortcomings due to solubility limitations of acetate or formate salts. In recent years, several alternatives have been developed, including aminocarboxylic acids and long-chained carboxylic acids. These long-chained carboxylic acids offer low corrosion rates, good dissolving power at high temperature, high biodegradability, and easier and safer to handle.Many experimental and theoretical studies in carbonate acidizing have confirmed the existence of an optimal acid injection rate at which major wormholes are formed, and the benefit from stimulation is maximized. This optimal rate depends on reservoir conditions, rock properties and chemical reaction rate of the acid being used. In our previous study, a theoretical model showed that under the same conditions, the optimal injection rate for weaker acids is lower than that for stronger acids. This paper presents a comparison of the efficiency of stimulation in carbonate acidizing of three different kinds of high temperature stimulation fluids. A chelating agent, EDTA, acetic acid, and a mixture of long-chained carboxylic acids were used to acidize carbonate cores at high temperatures. The effectiveness of the process and the optimal injection rate were studied by measuring the acid volume needed to propagate wormholes through 4-inch cores. The dendritic nature of the acid penetration was also determined by making castings of the wormhole structures after acidizing. The experimental results from this study showed that the optimal injection rate of longchained carboxylic acids is lower than that for acetic acid and the EDTA. This increase in efficiency then determines that a deeper and more efficient stimulation per gallon of acid mixture used is obtained with the long-chained carboxylic acids.
Nanoparticle dispersions (NPDs) are an emerging new technology in the oil and gas industry which can be applied to EOR, well remediation, and formation damage removal to stimulate hydrocarbon production using the unique properties that colloidal particles possess. Nanoparticles have a high surface area to volume ratio allowing a greater efficiency for chemical interactions to occur. However, nanoparticle dispersions are often difficult to stabilize in harsh downhole environments. The dispersion can quickly become unstable and agglomerate when the fluid is subjected to changes in pH, or encounters increased salinity and/or temperature. Agglomeration renders the fluid ineffective, and at worst can cause severe damage to the formation. The development of highly concentrated nanoparticle dispersions stable in high TDS brine at high temperatures has been achieved and verified in the laboratory with imbibition tests and dynamic core flow experiments. NPDs can be stabilized in the reservoir by altering charge density, hydrodynamic diameter, and the zeta potential of the particles. This is accomplished by surface modification, as well as with the addition of stabilizing chemistry. This paper presents solutions to the destabilizing elements encountered in the reservoir, that until now have inhibited the downhole utilization of nanoparticle dispersions. Stability research of NPD fluids in brines empirically illustrates that by chemically modifying the particle surface and the surrounding aqueous environment, the fluids will remain properly dispersed and active in destabilizing bottomhole conditions. This will further pave the way for industry research into new applications of nanoparticle based fluid systems.
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