Fluid Gel Research Articles

A New Hydraulic Fracturing Process

In this new fracturing method, high-viscosity fracturing fluids are used to obtain greater fracture length and width. The technique is characterized by higher propagation pressures and lower fluid loss at the fracture face. A film of water surrounding the fracturing fluid reduces friction losses in the tubing, and this lowers surface treatment pressures and pumping power requirements. Introduction A new method has been developed in which high-viscosity fracturing fluids are used for stimulating production from formations having a wide range of production from formations having a wide range of permeabilities. The fluids that have been used to date permeabilities. The fluids that have been used to date have ranged generally from about 500 cp to about 100,000 cp at ambient temperatures. The new method is used commercially under the names "Superfrac", "Super Frac", and "Super Sand Frac". The preferred fluids for use in the new method are loose water-in-oil dispersions or emulsions prepared by blending brine and a surface-active agent into a crude oil or petroleum fraction that has these high viscosities. When properly prepared, these emulsions will not readily change composition in the presence of free water. The emulsions are isolated from the inner wall of the tubing string or casing by a film of free water during injection and are generally pumped with about the same pressure drop as 1-cp oil or water. Studies indicate that the free water is lost to the formation after the fluids enter the fracture and that the high viscosity fracturing fluid remains behind for propagation of the fracture and placement of the propping agent. propping agent. This technique can be used to fracture any formation, but it has particular advantages when a large fracture conductivity ratio cannot be realized with small proppants, when thick or high-permeability formations are to be fractured, when a well must be fractured through small-diameter tubing or casing, and when proppant must be carried great distances from the wellbore. This paper gives the relationships of fluid viscosity to fracture geometry and proppant placement, establishes the advantages of using high-viscosity fluids for stimulating high- and low-permeability formations, and tells how the high-viscosity fluid system is maintained and pumps and Field tests have shown that excellent, sustained productivity increases have been obtained with this new hydraulic fracturing process. Fracture Geometry The use of very viscous oils as fracturing fluids has several benefits, including good fluid-loss control, increased fracture width, and improved sand transport. Fluid Loss Control Since Howard and Fast showed that the rate of fluid leakoff from a fracture depends upon the resistance of the invaded zone, the resistance of the filter cake, and the resistance of the compressible formation fluids, much of the work on fracturing has been directed toward the use of water-based fluids that can be injected at high rates and toward the development of better fluid loss control additives. Results to date indicate that gelled fluids and other water-based systems generally have low viscosities under the temperature and shear conditions existing in most fractures, and also that fluid loss control additives are normally much less effective under dynamic filtration conditions than they were once thought to be. Increased fluid loss can explain many of the difficulties encountered in conventional fracturing operations. JPT P. 89

Horizontal Fracture Design Based on Propped Fracture Area

Abstract Present fracture design procedures are based on the total fracture area created. A method to distinguish between total area and the propped or effective fracture area has not been available. This paper presents a solution to this problem, applicable to horizontal fractures. The differences between effective fracture area and total area are demonstrated in example calculations. This work is based on experimentally determined transport efficiencies of solids in sand-liquid slurries. Newtonian and non-Newtonian systems are considered. Introduction Fifteen years after commercial introduction, hydraulic fracturing remains the most successful stimulation technique in the oil field. This success is primarily due to ability of induced fractures to penetrate and alter permeabilities deep within formations. Many fields producing today could not have been developed without the hydraulic fracturing process. Because of wide usage, fracture-treatment design has received a great deal of engineering and research effort. This work, resulting in improved equipment and materials, has increased the benefits from fracture treatments as well as the applicability of the process. A major contribution was the development of fluid-loss additives. Necessarily, the number of parameters to be considered in treatment design has steadily increased, resulting in more complicated design techniques. Almost all present design procedures are based on the precepts set forth by Howard and Fast. Relating the fluid volume lost into the formation, the volume required in extending the fracture, and the total slurry volume injected. They developed an expression for the total fracture area created in terms of pertinent treatment parameters. Fluid loss during treatment was expressed as a function of time for three flow mechanisms. Although modifications of fluid loss equations have been made, the total fracture area concept has remained unaltered. A vast amount of field data indicate that induced fractures must be propped and held open to be effective. A notable exception is the Mesa Verde formation in the San Juan basin. However, analysis of these treatments shows that improved well productivities are obtained when propping agents are incorporated in the treating fluid. Although propped fracture area has been recognized as an important design parameter, a method to distinguish between total area and effective fracture area has not been available. The necessary information on slurry-sand transport in fractures has been lacking. Interest in the propped region of induced fractures is not restricted to areal extent alone. The distribution of sand within fractures is important from the standpoint of fracture flow capacities. Flow capacity affects the increase in well productivity after stimulation. The work of Huitt and Darin shows that partial monolayers of sand have large flow capacities compared to thick, dense sand packs. It has been postulated that gelled fluids have the ability to transport sand within the fractures at the desired low concentrations. An early contribution in the area of sand placement in fractures was made by Kern et al. They studied sand movement in a transparent vertical fracture model. It was observed that the sand tended to settle out in the bottom of the model before moving very far. When the fluid velocity exceeded a certain critical value, all of the sand injected began moving through the crack even though it settled to the bottom. This critical velocity was determined under several flow conditions. Some work on sand movement in horizontal fractures has been reported in Russian publications. Sand movement was studied by Izyumova and Shan'gin using a transparent "pie-shaped" flow model to simulate a horizontal radial flow system. However, the data were limited, especially in a quantitative sense. Dorozhkin, Zheltov and Zheltov studied the behavior of sand-liquid slurries in a horizontal linear flow model. The quantitative data were restricted primarily to the thickness of sand deposits formed at the bottom of the fracture. An earlier paper provided basic data on the flow of sand in horizontal fractures. This study was designed to yield specific quantitative information on rate of advance of sand particles and pressure behavior under various flow conditions. A comprehensive photographic study was undertaken in a 10-ft windowed flow cell to provide the necessary qualitative and quantitative data. Since the number of potential variables far exceeded the capacity of the initial study, emphasis was placed on the effects of sand concentration, oil viscosity and oil flow rate. A detailed description of these experiments and the results are described in Ref. 9. However, the implications of this work on the fracture design calculations were not discussed. An analysis of these data as well as new data is provided in the following sections. EXPERIMENTAL RESULTS The primary objective of the experimental investigation was to provide information on the rate of advance of the solids in sand-liquid slurries. JPT P. 723ˆ

Movement of Hydraulic Fracturing Sand

Hydraulic fracturing makes the very permeable channel, where the fracture is created in the reservoir formation by the injection of fluid suspending sand with high pressure and high rate and then the openning of fracture is filled up with sand carried in the fracturing fluid, for the purpose of elevating the productivity or flowing capacity of oil reservoir. Therefore, the study on the movement of sand during the fracturing procedure, especially transportation and deposition of sand in the fracture openning, is thought to be very useful for understanding of fracturing process and promoting its effectiveness.This paper states, first, the experimental and theoretical studies on the precipitation of sand grains in the non-flowing fluid and experiment of sand movement in the flowing fluid in the fracture openning, which is represented by the model apparatus. The sand mixed in the flowing fluid precipitates and deposits to the bottom of channel because of gravity segregation, when the flow rate is low. But when the flow rate reaches to the certain degree, the equilibrium is obtained such as no more precipitation of sand occures nor the previously deposited sand moves. The velocity of this state is defined as equilibrium velocity. This paper reveals the equilibrium velocities, which are obtained experimentally for sands in water, medium weight crude oil and the gel fluid and discussion about movement and deposition of sand in the fracture openning by application of those data. Furthermore, a few points, which should be considered carefully at the fracturing practices, are induced.

Simplified practice recommendation no. 10—Milk and cream bottles and bottle caps

The specific volumes of six 1,2-diacylphosphatidylcholines with monounsaturated acyl chains (diCn:1PC, n = 14–24 is the even number of acyl chain carbons) in fluid bilayers in multilamellar vesicles dispersed in H2O were determined by the vibrating tube densitometry as a function of temperature. From the data obtained with diCn:1PC (n = 14–22) vesicles in combination with the densitometric data from Tristram-Nagle et al. [Tristram-Nagle, S., Petrache, H.I., Nagle, J.F., 1998. Structure and interactions of fully hydrated dioleoylphosphatidylcholine bilayers. Biophys. J. 75, 917–925.] and Koenig and Gawrisch [Koenig, B.W., Gawrisch, K., 2005. Specific volumes of unsaturated phosphatidylcholines in the liquid crystalline lamellar phase. Biochim. Biophys. Acta 1715, 65–70.], the component volumes of phosphatidylcholines in fully hydrated fluid bilayers at 30 °C were obtained. The volume of the acyl chain CH and CH2 group is VCH = 22.30 Å3 and VCH2 = Å3, respectively. The volume of the headgroup including the glyceryl and acyl carbonyls, VH, and the ratio of acyl chain methyl and methylene group volumes, r=VCH3:VCH2 are linearly interdependent: VH = a − br, where a = 434.41 Å3 and b = −55.36 Å3 at 30 °C. From the temperature dependencies of component volumes, their isobaric thermal expansivities (αX=VX−1(∂VX/∂T) where X = CH2, CH, or H were calculated: αCH2=118.4×10−5K−1, αCH = 71.0 × 10−5 K−1, αH = 7.9 × 10−5K−1 (for r = 2) and αH = 9.6 × 10−5 K−1 (for r = 1.9). The specific volume of diC24:1PC changes at the main gel–fluid phase transition temperature, tm = 26.7 °C, by 0.0621 ml/g, its specific volume is 0.9561 and 1.02634 ml/g at 20 and 30 °C, respectively, and its isobaric thermal expansivity α = 68.7 × 10−5 and 109.2 × 10−5 K−1 below and above tm, respectively. The component volumes and thermal expansivities obtained can be used for the interpretation of X-ray and neutron scattering and diffraction experiments and for the guiding and testing molecular dynamics simulations of phosphatidylcholine bilayers in the fluid state.