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Abstract Several different hydraulic fracturing treatment design methodologies have been adopted and used with varying success in East Texas and, specifically, in the Cotton Valley Sand Formation. Treatment designs have ranged from massive hydraulic fractures using crosslinked polymer fluids to low proppant concentration slickwater treatments (waterfracs) using only water plus a friction reducer. Operators have varying opinions regarding the benefits of the various design approaches, with the only common conclusion being that hydraulic fracturing must be employed to commercially produce hydrocarbons from these tight formations. The major design challenges include the need for long fractures, relatively limited height growth, good proppant coverage over the entire fracture surface, and low proppant pack damage. Neither conventional fracturing treatments nor slickwater fracturing treatments address all of these issues. To meet the challenging design requirements, a new design methodology in which fibers are added to the fracturing fluid has resulted in added benefits for operators. The fibers assist in the transport of proppant based on a mechanical suspension mechanism and prevent proppant settling during fracture closure. As a result, the fluid viscosity is no longer the main factor in proppant transport and significantly lower polymer concentrations can be used without compromising proppant transport. For example, the polymer concentration used in several successful treatments at BHST in excess of 250°F has been reduced by about 50% when used in conjunction with the fibers. The lower fluid viscosity allows for the creation of the desired fracture geometry with controlled fracture height growth. In addition, reducing the polymer concentration has largely been accepted as a means to increase fracture conductivity. The use of fibers in conjunction with the polymer fluid is a new approach that has allowed for additional reduction in polymer loadings while still maintaining excellent proppant transport in over 90 jobs pumped to date. The purpose of this paper is to share the fracture design methodology incorporated for several operators completing wells in East Texas. Typical job designs with fluid rheology and laboratory conductivity data are presented in conjunction with the placement success when using the fiber assisted transport design methodology. Initial production results are reviewed and compared to offset wells that have been stimulated using conventional methods. Introduction Slickwater fracturing treatments (often referred to as waterfracs) are commonly used in East Texas due to economic benefits. Published literature suggests adequate conductivity can be attained by pumping large volumes of slickwater (water plus friction reducer) with very low concentrations of sand and even cases that suggest adequate conductivity is obtained without proppant. Generally, the literature reports that the conductivity is generated by fractures that never completely close, but the mechanism by which these treatments provide sufficient conductivity is not well understood. The presence of residual fracture width caused, for example, by surface asperities and proppant bridging, and the lack of damage associated with the use of gels in conventional proppant treatments, are possible explanations. However, research conducted on hydraulically fractured Cotton Valley cores show that fracture displacement is required for the surface asperities to provide sufficient conductivity without the use of proppants. Further investigations in a study of slickwater versus conventional fracturing treatments within the Cotton Valley sands show conventional fracturing treatments, on average, produce 38% more gas in the first year versus the slickwater fracturing treatments when normalized for reservoir and producing system conditions.
Samuel, Mathew (Schlumberger) | Polson, Dan (BP Amoco) | Graham, Don (Schlumberger) | Kordziel, Walt (Schlumberger) | Waite, Tim (Schlumberger) | Waters, George (Schlumberger) | Vinod, P.S. (Schlumberger) | Fu, Dan (Schlumberger) | Downey, Rich (Schlumberger)
The introduction of viscoelastic surfactant (VES) base fracturing fluids haschanged the way industry views fracturing fluids and proppant transport duringa fracture treatment.1 Elimination of polymers allows one to achievehighly conductive proppant packs with no polymer damage. Retained permeabilityand leakoff control are two of the most important requirements for fracturingfluids. Traditional and new generations of cross-linked gels provide goodleakoff control, but they often adversely affect the retained permeability ofthe proppant pack. In addition, minimizing frac-height growth and increasingeffective fracture length are a few other advantages of using VESfluids.2
In the majority of cases in low permeability formations, a long andconductive fracture is the ultimate aim of hydraulic fracturing. Borate ormetal crosslinked guar fluids, because of their inherent high viscosity,typically result in height growth rather than increased fracture length. WithVES fluids proppant transport is based on the elasticity and structure ratherthan the viscosity of fluid. Therefore VES fluids efficiently transportproppants at lower viscosities. At the same time, VES fluids let one achieve abetter fracture geometry, that with minimum fracture height and maximumfracture length. Pressure transient analysis and tracer studies have shown thatthis non-damaging low viscosity fluid can give longer effective frac-lengtheven when using much less fluid and proppant volumes (Figure 1). Reducedfriction pressure is another added advantage while using VES fluids. Hence VESfluid is the fluid of choice when fracturing is performed through coiledtubing.3,4 Simplicity and reliability of this two component systemare the other features of this fluid that attract the industryglobally.5
The use of VES technology is now extended to other oilfield applications,such as selective matrix diversion,6 filtercake removal,7and coiled tubing clean out. VES technology is also defining new engineeringpractices in hydraulic fracturing that cannot be accomplished with conventionalfluid systems, such as fracturing through coiled tubing.
Hydraulic fracturing has long been considered an effective stimulationtreatment for low permeability formations. In these treatments, the goal is tocreate a long, thin fracture that provides a large surface area. Fracturehalf-lengths can be of the order of 100 to 1000 ft and have widths in the orderof tenth of an inch.
The perception that a successful hydraulic fracturing treatment is the onethat was pumped without problems, has changed in the industry. The true measureof a successful fracturing treatment is increased production or injectivity.The key objective is to improve fluid communication between reservoir and thewellbore. Polymer residues that stay in the fracture contribute significantlytowards lower proppant pack permeability, thus leading to a loss in treatmenteffectiveness. Laboratory experiments have shown that unbroken residues frompolymer-base fluids can indeed plug the pores of the proppant pack. Analysis ofthe flowback fluid obtained from wells treated with conventional and low guarfluids indicates that even in low permeability reservoirs, only 35 to 45% ofthe polymer that is pumped during the treatment flows back during the flowbackperiod.8 The remaining polymer stays in the fracture and willadversely affect the well productivity.
An ideal fracturing fluid should show minimal pressure drop in the pipeduring placement, should have adequate proppant carrying ability and shouldinactivate the transport mechanism after the fracture closes. This will allowthe fluid to break and flowback without leaving any residue that minimizesconductivity.
Huang, Hai (Xi'an Shiyou University and Shaanxi Key Laboratory of Advanced Stimulation Technology for Oil & Gas Reservoirs) | Babadagli, Tayfun (University of Alberta) | Andy Li, Huazhou (University of Alberta) | Develi, Kayhan (Istanbul Technical University)
Abstract The fracture-surface characteristics (such as roughness and fractal dimensions) may greatly affect the proppant transport during hydraulic fracturing operation. Few researches have focused on investigating the proppant transport in vertical fracture with actual surface characteristics. As a continuation of our previous study (Huang et al. 2017), we qualitatively investigatethe migration of proppants in rough and vertical fractures by considering the effects of surface characteristics and rock type on the instantaneous transport and areal spreading of proppant in the fractures. We fractured different types of tight rocks (including limestone, marble, tight sandstone, and granite) with Brazilian test and molded them to manufacture 20×20cm transparent replicas with an aperture of 1 mm. We characterized the surface characteristics of these rock samples with different fractal dimensions. Subsequently, dyed fracturing fluid with or without proppant loading was injected into the rough vertical fracture. In each test, we monitored the inlet pressure continuously while the proppants were being transported in the fracture. The process was videotaped to monitor the proppant distribution in the rough fracture. Different from our previous study (Huang et al. 2017), a higher injection rate is used in this present study. The experimental results obtained in this study further consolidate the many findings reported in our recent study (Huang et al. 2017): in rough and narrow fracture, the surface roughness plays a pivotal role in affecting how proppants settle in the fracture as well as where the proppants settle in the fracture. Roughness of the vertical fractures tends to significantly enhance the vertical placement of proppants in the fracture, leading to a much higher proppant-filling ratio in a rough fracture than in a smooth fracture. Interestingly, in addition to the bridging effect observed in Huang et al. (2017), a previously formed proppants cluster can be broken up under a higher-rate slurry flow. The bridging of proppants and its subsequent breaking up can recursively occur during the high-rate slurry flow, resulting in fluctuations in the proppant filling ratios as well as fluctuations in the pressure profiles recorded in the inlet of the fracture model. The roughness of fracture models not only affects how much area of the fracture is being occupied by the proppants in the fracture, but also affects how tightly the proppants are filling up the fracture. Different types of rock have different surface characteristics, leading to the observed differences with regard to how the proppants migrate, settle down and fill up the fractures. No definite correlation could be established between any of the fractal numbers and the relative coverage of proppants in the fracture. More experiments, however, need to be conducted to reach more concrete conclusions in this regard.
Summary New fracturing techniques, such as hybrid fracturing (Sharma et al. 2004), reverse-hybrid fracturing (Liu et al. 2007), and channel (HiWAY) fracturing (Gillard et al. 2010), have been deployed over the past few years to effectively place proppant in fractures. The goal of these methods is to increase the conductivity in the proppant pack, providing highly conductive paths for hydrocarbons to flow from the reservoir to the wellbore. This paper presents an experimental study on proppant placement by use of a new method of fracturing, referred to as alternate-slug fracturing. The method involves an alternate injection of low-viscosity and high-viscosity fluids, with proppant carried by the low-viscosity fluid. Alternate-slug fracturing ensures a deeper placement of proppant through two primary mechanisms: (i) proppant transport in viscous fingers, formed by the low-viscosity fluid, and (ii) an increase in drag force in the polymer slug, leading to better entrainment and displacement of any proppant banks that may have formed. Both these effects lead to longer propped-fracture length and better vertical placement of proppant in the fracture. In addition, the method offers lower polymer costs, lower pumping horsepower, smaller fracture widths, better control of fluid leakoff, less risk of tip screenouts, and less gel damage compared with conventional gel fracture treatments. Experiments are conducted in simulated fractures (slot cells) with fluids of different viscosity, with proppant being carried by the low-viscosity fluid. It is shown that viscous fingers of low-viscosity fluid and viscous sweeps by the high-viscosity fluid lead to a deeper placement of proppant. Experiments are also conducted to demonstrate slickwater fracturing, hybrid fracturing, and reverse-hybrid fracturing. Comparison shows that alternate-slug fracturing leads to the deepest and most-uniform placement of proppant inside the fracture. Experiments are also conducted to study the mixing of fluids over a wide range of viscosity ratios. Data are presented to show that the finger velocities and mixing-zone velocities increase with viscosity ratio up to viscosity ratios of approximately 350. However, at higher viscosity ratios, the velocities plateau, signifying no further effect of viscosity contrast on the growth of fingers and mixing zone. The data are an integral part of design calculations for alternate-slug-fracturing treatments.
Bulova, Marina Nikolaevna (Schlumberger R&D Inc.) | Cheremisin, Alexey Nikolaevich (Schlumberger R&D Inc.) | Nosova, Ksenia Evgenievna (Schlumberger R&D Inc.) | Lassek, John T. (Schlumberger) | Willberg, Dean
Abstract To achieve maximum production, tight-gas formations require long fractures with contained height growth. This can be achieved by using low viscosity fracturing fluids. Decrease in fluid viscosity typically leads to an increase of proppant settling rate which results in non-uniform proppant placement and reduced effective fracture conductivity. Low-density proppants can offset this effect in low-viscosity fluid, but due to their low strength can be applied only at low closure stresses and relatively low temperatures. A new fluid system was developed especially for fracturing low-permeability formations (less than 0.01 mD). This system allows for high-strength high-density ceramic proppant to be used with reduced polymer loading and significantly decreased proppant settling rates. All these benefits are the result of adding fibers into a fluid system which create a network, helping to suspend proppant during its transport and placement into a fracture. Laboratory studies were performed to determine the fiber's influence on long-term proppant-pack permeabilities. Retained conductivities of ceramic and sand proppant packs over the 175–250 ºF temperature range were measured under various loadings and closure stress ranges. Testing has shown permeability values of the fiber-laden systems are comparable with the values for fiber-free proppant packs. A parallel study was performed on evaluating proppant settling rates in fiber-laden fluids in static conditions. Fiber in a fracturing fluid system reduces the rate of proppant settling by greater than three-fold. Special attention is paid to a proper proppant selection for hydraulic fracturing. Improper proppant selection can cause significant damage of proppant pack conductivity and minimize benefits of the fluid system. The results prove that the innovative fiber fluid ensures uniform proppant placement within a long fracture because of fiber presence, provides conductivity comparable to pure proppant pack values, and do not have any limitations at high closure stresses. Introduction Fracture conductivity can be optimized by using the most crush-resistant proppant economically feasible for a given closure stress. The long-term crush resistance of commonly used proppants usually correlates with the specific gravity of the material, but the high settling rates of higher strength materials in low viscosity fluids can create short effective fractures with poor vertical proppant distribution. This issue is especially critical in low-permeability tight gas formations where the extended fracture closure times lead to poor proppant distribution and therefore long effective fractures are desired and low-viscosity fluids are the norm. Due to perceived economic benefits the tight gas market in US is primarily served by slickwater fracturing treatments (often referred as waterfrac treatments) consisting of large volumes of water with friction reducer and low or even zero sand concentration. One of the ways to reduce particle settling is to develop low-density proppant materials. However, due to their low strength they cannot be applied in tight gas formations with high closure stresses. Literature data show that low-density proppant pack conductivity significantly declines at closure stresses higher than 5,000 psi and becomes comparable to sand performance.[2,3] Based on the fact that currently there is no economically efficient low-density proppant available for application in majority of tight-gas formations, alternative ways of optimal proppant placement should be considered. One such innovative approach consists in development of fiber-laden fracturing fluid capable of placing high-strength, higher specific gravity proppant uniformly throughout a fracture. A network of degradable fibers in the fluid minimizes proppant settling and mechanically transports the proppant as it moves deeper into the fracture. Since a reduction of proppant settling rate in this case does not depend on gel viscosity, lower than conventional polymer concentrations can be used for these fracture treatments. Combined with another advantage of this fluid system, namely fiber degradation under bottomhole conditions over time, this leads to reduced fracture conductivity damage comparable with a conductivity of pure fiber-free proppant pack.