Hydraulic fracturing is used extensively to increase hydrocarbon production from oil and gas formations. Hydraulic fracture conductivity is a key parameter in optimizing the productivity of a well after the fracture treatment. The American Petroleum Institute (API) proppant permeability / fracture conductivity testing results are frequently used in industry fracturing models when selecting the proppant that provides the optimum fracture conductivity for a well's particular reservoir properties. This design methodology invariably results in a lower than expected fracture conductivity and in many cases, lower than optimum well performance. The industry has recognized that actual fracture conductivity is often a small fraction of what would be expected by using API test results. Non-Darcy flow, multiphase flow, gel damage, stress cycling, fines migration, proppant embedment, proppant flowback, and fracture cleanup are some of the parameters that result in fracture conductivities significantly lower than those measured in an API conductivity test. A new proppant was developed to improve the final fracture conductivity achievable with high-strength spherical proppants currently available in the market place. This new product is an elongated rod-shaped, high-strength particle with integrated proppant flow back control. Initial field testing of the product was conducted in moderate permeability formations where production from prior fracture treatments indicated lower than optimum fracture conductivity. Production results from these field tests confirmed that substantial increases in fracture conductivity can be achieved. The large improvement seen in fracture conductivity can be attributed to increased porosity of the proppant pack and reduced fracture conductivity losses due to non-Darcy and multiphase flow effects. Completely changing the typical geometry of proppants used in hydraulic fracturing is a viable option for improving the conductivity of hydraulic fractures to a point not currently obtainable with spherical proppants.
Production from shale gas reservoirs depends greatly on the efficiency of hydraulic fracturing treatments. The cumulated experience in the industry has led to several best practices in treatment design, which have improved productivity of these reservoirs. However, further advancement of treatment design requires a deeper understanding of the complex physics involved in both hydraulic fracturing and production, such as stress shadow, proppant placement and treatment interaction with pre-existing natural fractures. This paper sheds light on the non-linear physics involved in the production of shale gas reservoirs by improving the understanding of the complex relation between gas production, the reservoir properties, and several treatment design parameters. A fracturing-to-production simulation workflow integrating the Unconventional Fracture Model (Weng et al., 2011), with the Unconventional Production Model (Cohen et al., 2012) is presented. By applying this workflow to a realistic reservoir, we did an extensive parametric study to investigate the relation between production and treatment design parameters such as fracturing fluid viscosity, proppant size, proppant concentration, proppant injection order, treatment volume, pumping rate, pad size and hybrid treatment. The paper also evaluates the influence of unconventional reservoir properties -such as permeability, horizontal stress, horizontal stress anisotropy, horizontal stress orientation, Poisson's ratio and Young's modulus -on production. Since this paper focuses on fluid and proppant selection, our methodology was to run 28 simulations to cover the 2D parametric space of proppant size and fracturing fluid viscosity for all of these parameters. More than fourteen hundred simulations were run in this parametric study and the results provide guidelines for optimized treatment design. This paper illustrates how this unique workflow can identifies the optimum fluid and proppant selection that gives the maximum production for a given reservoir and completion. In addition, the parametric study shows how these optimums evolve as a function of reservoir and treatment parameters. The results validate several best practices in treatment design for shale. For example, combination of different sizes of proppant optimizes production by maximizing initial production and slowing down production decline. Simulations also confirm the best practice of injecting the smallest proppant first. The study explains why slickwater treatments should be injected at maximum pumping rate and preferably with 40/70 mesh sand. It also illustrates why reservoirs with high Young's modulus (such as the Barnett shale) can be stimulated effectively with slickwater. Another key finding is that the optimum fluid viscosity increases with treatment volume.
Production from shale gas reservoirs depends greatly on the efficiency of hydraulic fracturing treatments. The cumulated experience in the industry has led to several best practices in treatment design which have improved productivity in these reservoirs. However, further advances in treatment design require a deeper understanding of the complex physics involved in both hydraulic fracturing and production, such as stress shadow, proppant placement and interaction with natural fractures. This paper investigates the non-linear physics involved in the production of shale gas reservoirs by improving the understanding of the complex relation between gas production, the reservoir properties, and several treatment design parameters, with a focus on proppant and fluid selection. A fracturing-to-production simulation workflow integrating the Unconventional Fracture Model, with the Unconventional Production Model is presented. This workflow has shown qualitative consistency with real production data. In this paper we applied the workflow on a realistic reservoir with characteristics from the Marcellus play, and then studied the relation between production and treatment design parameters such as proppant size, proppant concentration, the treatment volume of the treatment, fracturing fluid viscosity, pumping rate and proppant injection sequence. Since this paper focuses on fluid and proppant selection, our methodology was to run 28 simulations to cover the 2D parametric space of proppant size and fluid viscosity for every parameter. More than four hundred simulations were run in this parametric study and the results provide guidelines for optimized treatment design. The behaviors observed confirm several best practices in treatment design for shale. For example, combination of different sizes of proppant optimizes production by maximizing initial production and slowing down production decline. Simulations also confirm the best practice of injecting the smallest proppant first. Another key finding is that the optimum fluid viscosity increases with treatment volume, and decreases when pumping rate increases.
Synthesis of mullite from a mixture of a-Al 2 O 3 + b-SiO 2 and native kaolin-based materials in the presence of nanodisperse aluminum is reported. In both cases, addition of nanodisperse Al increases the yield of mullite and stabilizes its structure.Materials based on mullite (3Al 2 O 3 × 2SiO 2 ), owing to their unique mechanical and thermophysical properties, have been gaining ever-increasing acceptance in the production of refractories and engineering ceramics. Mullite may be used as a single basic phase or in combination with oxide [1] or metallic ingredients [2]. Nanodisperse metallic powders, owing to their high reactivity, can be used both as components of a metal ceramic composites and as an active mixture component involved in the solid-phase synthesis of new phases [3]. Heating mixes containing nanodisperse aluminum in an oxidizing medium initiates sequential reactions of which metal oxidation and mullitization are central.The synthesis of mullite containing nanodisperse aluminum was carried out by heating mixes of two composition: (i) based on oxides of aluminum and silicon and (ii) based on kaolinite with aluminum oxide added. Aluminum oxide was calcined vibroground alumina (a-Al 2 O 3 ) with average particles size of 5.6 mm; silicon dioxide was a finely ground sand (from the Tuganskoe deposit) treated using hydrocyclone and electroseparator techniques. The basic component was b-SiO 2 (up to 99.10%) and the minor components were iron oxide (0.04%) and aluminum oxide (0.46%); the average size of wet-ground particles was 10 mm. The major component of kaolin mixes was kaolin from the Zhuravlinyi Log deposit; the base material was ³ 97.5%, the total of minor oxides was £ 2.41%.The mullitization reaction was activated by adding ultradisperse aluminum with an average particle size of 80 nm. Aluminum was added at a concentration of 0.2 -5 wt.%. The proportion of components in the mixtures was in conformance with the mullite stoichiometry. The aluminum concentration was corrected for subsequent oxidation to Al 2 O 3 . The specimens were molded by semi-dry pressing under a load of 50 MPa and heated in air at a rate of 1.5 K/min to 1000°C; on reaching this temperature, the heating rate was increased to 200 K/h. The holding time at maximum temperature varied from 30 min to 5 h. The synthetic mullite phase was quantitated by an x-ray reflection peak (110) (interplanar spacing 0.540 nm).The synthesis of these two types of specimens and the involvement of nanodisperse aluminum exhibit specific features. The synthesis in kaolinite-containing mixtures is more energetically favorable in comparison to the pure-oxide process. Mullitization of kaolinite in the early stage involves the formation of a "primary" mullite with the onset at about 1200°C; at temperatures above 1300°C, a "secondary" mullite is formed. The rate of formation of mullite in mixtures containing natural kaolin at 1300°C is higher than that in oxide-containing mixtures (Fig. 1); for this reason, the activating effect due to the high-disperse additive ...
The Volga-Urals basin is one of the largest oil-producing regions in Russia. Orenburg region, located in Volga-Urals, has more than 100 oil fields with great variety of formation properties. The majority of formation fluids are characterized by high gas/oil ratio (GOR) and high bubblepoint pressure. Today, most reservoirs are depleted and produce at bottomhole flowing pressure below bubblepoint pressure. These factors yield multiphase and non-Darcy flow in propped hydraulic fractures, which drastically decreases production. As a result, hydraulic fracturing treatments with conventional proppant are not effective.Proppant flowback is another critical problem after hydraulic fracturing. There are a few solutions widely accepted by industry, and one of the most popular is a resin-coated proppant (RCP). Usually the coating is activated by temperature; however, for formations with low bottomhole static temperature (BHST), RCP may not be efficient. Many formations in Volga-Urals have a low BHST, which requires a different technology from RCP to eliminate proppant flowback.A recently developed rod-shaped proppant was proposed as a solution to both problems specified above. In comparison with conventional proppant, it provides higher fracture conductivity with integrated flowback control due to random alignment of proppant grains while packing. This property results in improved fracture cleanup from treating fluids. The rod-shaped proppant also acts to prevent proppant flowback through specific shapes of grains. The significant benefit over conventional RCP is that rod-shaped proppant does not have any BHST limitations, does not require any chemical activation, and does not have special flowback requirements.Since the introduction of rod-shaped proppant in Russia, 10 fracturing treatments have been successfully carried out with this new proppant in Vakhitovskoe, Lebyzhinskoe, Vostochno-Kapitonovskoe, and Sorochinsko-Nikolskoe oil fields. Well production analysis proved that rod-shaped proppant was more effective than conventional proppant: productivity index is 26 to 67% higher. Further, no proppant flowback issues were detected on wells fractured with rod-shaped proppant. The first successful implementation of this product in Russia is described in detail with laboratory data, a thorough production analysis, and case histories. Pump rate (m3/min) / Расход (м3/мин) Pressure (bar), Proppant concentration (KgPA) / Давление (бар), концентрация проппанта, (кг/м3) Time (hh:mm) / Время (чч:мин) Lebyazhenskoe L26 D1 / Лебяженское L26 Д1 Main Job / Отчёт по Обработке ГРП Treating Pressure (bar) / Давление в линии (бар) Annulus Pressure (bar) / Давление в затрубье (бар) Prop Con POD Densitometer (KGPA) / Концентрация проппанта с плотномера блендера (кг/м3) BH Prop Con POD Densitometer (kg/m3) / Концентрация проппанта на забое с плотномера блендера (кг/м3) Bottomhole Pressure Measured (Bar) / Замеренное забойное давление (бар) Slurry Rate In-line Flowmeter (m3/min) / Расход жидкости с расходомера (м3/мин)
Different applications of fracture bridging and diversion are used regularly in carbonate acid fracturing without an in-depth understanding of the physical phenomena that dominate the processes involved in the bridging and diversion process. The extension of modeling capabilities in conjunction with yard-scale and field-scale experiences will increase our understanding of these processes. A robust multimodal diversion pill and polylactic acid fiber-laden viscous acid were utilized for near-wellbore and far-field bridging, respectively. Numerous field treatments demonstrated the uncertainty of achieving effective diversion. An existing multiphysics model was extended to develop functionalities to model diversions at different scale. Extensive laboratory testing was conducted to understand the scale of bridging and diversion mechanisms. Finally, a bridging yard test was designed, and field case studies were used to integrate all the branches. Field cases showed a diversion pressure up to 4,000 psi depending on perforation strategy, pill volume, and pill seating rate. Correlations showed the interdependence of multiple parameters in diversion processes. The field studies motivated modeling capabilities to simulate the critical diversion processes at high resolution and quality. The model simulates diverting agents that reduce leakoff in the fracture area and their effects on fracture geometry. The approach considers the acid reaction kinetics coupled with geomechanics and fluid transport. Different diverting agent concentrations required for bridging can be modeled effectively. A yard test was designed to confirm the integrity of the pill material through completion valves (minimum inside diameter 9.5 mm) and analyzed with high-resolution imaging. All the theoretical, mathematical, and numerical findings from modeling were integrated with laboratory- and yard-scale experimentation results to develop and validate near-wellbore and far-field diversion modeling. Analytical correlations were formulated from injection rate, particulate material concentration, pill volumes, fracture width, etc., to incorporate and validate the model. This study enhances understanding of the different diversion mechanisms from high-fidelity theoretical modeling approach integrated with a practical experimental view at laboratory and field scale. Current comprehensive research has significant potential to make the modeling approach a reliable method to develop tight carbonate formations around the globe.
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