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Understanding the causes of damage to fracture conductivity is vital to design fracture treatments for maximum economic value and to analyze the actual well performance. High-viscosity fluids, resulting from retention of polymer within the proppant pack during closure, play a major role in proppant-pack damage. Viscous fluids are not effectively displaced during flowback and production of hydrocarbon unless the viscosities of the phases are similar. The consequences of viscous fingering in the fracture are discussed, and a method is presented for predicting the retained permeability of proppant packs in which guar-based hydraulic fracturing fluids have been broken. Data required for the method are temperature, polymer molecular weight and final polymer concentration.
Proppant pack damage caused by polymeric fracturing fluids has generally been attributed to residue or high polymer concentrations remaining in the fracture after closure. For example, Cooke found that fluids which yielded lower volumetric levels of residue on breaking generally caused less pack damage.
Hawkins and Brannon and Pulsinelli placed greater emphasis on the difficulty of removing high polymer concentrations from the proppant pack. High polymer concentrations are the result of the filtration process which occurs during fracture closure. If the formation pore sizes are too small to allow invasion by guar molecules, the guar concentration in the fracture may increase dramatically.
According to the calculations of Brannon and Pulsinelli, a concentration factor of 10 is easily achieved for an average proppant concentration of 3 ppga. They reported that high breaker concentrations are necessary to effectively remove damage. Parker and McDaniel had similar concerns about high polymer concentrations, but they were particularly worried about removing the filtercake.
This paper discusses the damage to fracture conductivity resulting from channeling or viscous fingering. Fingering will occur during flowback following a fracturing treatment when low-viscosity fluIds (leakoff or formatIon fluid) pass through the degraded fracturing fluid remaining in the proppant pack. Fingering leads to bypassing of part of the pack, which causes a loss of effective fracture area. The extent of fingering can be predicted from the contrast between the viscosity of the fluid in the pack and the viscosity of the displacement fluid.
Holditch, Stephen A. (S.A. Holditch and Assocs. Inc.) | Robinson, Brad M. (S.A. Holditch and Assocs. Inc.) | Ely, John W. (S.A. Holditch and Assocs. Inc.) | Rahim, Zillur (S.A. Holditch and Assocs. Inc.)
A plot of excess pressure vs. time can be used to predict fracture-growth patterns only when both the viscosity of the fluid in the fracture and the stress at the fracture tip remain constant. This paper uses laboratory data and field examples to explain how increased friction owing to viscous slurries affects the interpretation of fracturing pressures. pressures. Introduction
Currently, no simple, affordable technique directly measures hydraulic fracture dimensions. However, one can estimate values of fracture length and fracture conductivity by history matching field data with numerical simulators. Two types of simulators can be used: a fracture-propagation model for analyzing fracture treatment pressures and a reservoir simulator for history matching the post, fracture production performance. Both analysis techniques have been described in the literature and are generally accepted in the industry.
Unfortunately, most engineers do not use numerical models to analyze field data because (1) the models are not available to the practicing engineer, (2) the input data needed to run the model are not available, and (3) most companies do not assign the manpower needed to solve the problem. As a result, more simplified analysis techniques are needed to evaluate hydraulically fractured reservoirs.
In 1979, Nolte and Smith presented a theoretical basis for understanding fracture-growth patterns and for estimating fracture dimensions on the basis of the interpretation of pressures measured during a fracture treatment. Specifically, by analyzing the excess pressure above closure pressure as a function of time, one could estimate the amount of fracture-height growth and/or the leakoff characteristics of the fluid in the fracture.
Since Nolte and Smith's paper was first published, the methods proposed have been widely accepted and practiced within the petroleum proposed have been widely accepted and practiced within the petroleum industry. In many situations, the interpretation of excess pressure has led to a better understanding of hydraulic fracturing and improvements in the stimulation process. In certain situations, however, the interpretation of excess pressure is more complex than assumed in Nolte and Smith's work. In this paper, data from actual fracture treatments and from laboratory measurements are used to extend Nolte and Smith's observations. The information and data presented here were developed during work done over the past several years under contract to the Gas Research Inst. (GRI).
Explanation of Original Concept
Nolte and Smith presented "a basis for interpreting fracture-treating pressures that permits identification of periods of confined-height pressures that permits identification of periods of confined-height extension, uncontrolled height growth, and, more importantly, a critical pressure." They used Eq. 1 to explain the relationship among fracture pressure." They used Eq. 1 to explain the relationship among fracture length, fracture height, fluid leakoff, and excess pressure in the fracture:
See Ref. 6 for the derivation of this equation.
Fig. 1 shows the various modes of pressure behavior observed in the original work. Mode 1 refers to the excess-pressure behavior expected on the basis of Nordgren's theories when a fracture is propagating. Nordgren's work assumed that the injection rate, injection-fluid viscosity, stress at the fracture tip, fracture height, and leakoff rate were all constant. Therefore, as the fracture length extended, the pressure in the fracture should increase with time. According to Nordgren's theories, during Mode 1 growth, fracture height is contained and the fracture grows normally.
ABSTRACT The enhancements to the oil production process produced by high viscosity friction reducers (HVFRs) has increased dramatically. The HVFR fluid improves processes during hydraulic fracture operations and provides a successful reduction in friction compared to the traditional treatment, which employs linear gel such as guar. The research aims to determine proppant capability performance of HVFRs and linear gel by conducting intensive laboratory investigations. These investigations aim to elucidate the effects of rheological fluids and fracture geometry on the static and dynamic settling velocity of the proppant inside fractures using HVFRs compared to linear gel fluids. Various concentrations of HVFR and guar were used for both the rheology and the proppant test experiments. The rheology and settling measurements show greater improvement of HVFR to distribute the proppant in the fracture compared to guar. Interestingly, a lower concentration of the HVFR (i.e., 2 gpt) provided improved viscosity and elastic properties than the standard concentration of linear gel (i.e., 20 ppt). This work will contribute to a better comprehension of HVFRs' ability to transport proppant. Ultimately, this improved understanding can assist hydraulic fracturing companies to build better friction reducers. 1. INTRODUCTION The main objective of a hydraulic fracture is to improve the formation conductivity and, subsequently, increase the production rate of oil wells. To achieve this, the sand carried inside the fracture must be distributed throughout the entire fracture length, with a lower surface treating pressure (Shen et al., 2018; Dahlgren et al., 2018). A traditional treatment system (hybrid system) works well where there is a high network complexity. This system also provides a good sand transport, especially at lower sand loadings or smaller mesh sizes. However, such systems require more chemicals, meaning greater tank and truck footprints, and larger amounts of water required to transport the proppant deep into the fracture (Zhao et al., 2018; Van Domelen et al., 2017). Moreover, this type of system is poorly equipped to carry the sand ftirther into the fracture, especially with higher proppant loadings or larger sand sizes. This can cause screenout due to the concentrated sand bank near the wellbore, which would require increased pumping pressure. The combination of these limitations increases the total cost of hydraulic fractures (Shen et al., 2018; Aften and Wason, 2009).
Abstract Most of the low-permeability tight gas market that is treated by low-viscosity slickwater fracturing treatments results in ineffective propped fractures due to rapid proppant settling. Currently hybrid fracturing and ultra-lightweight proppants are employed for improving performance of slickwater treatments. The hybrid fracturing methodology uses a combination of linear and crosslinked gels to improve proppant placement. The disadvantages of existing lightweight proppants are their high cost and applicability only to reservoirs characterized by low closure stresses. Novel fiber-laden low-viscosity fluid technology has been developed to improve proppant transport for hydraulic fracturing in low-temperature tight gas formations. Such a system creates a fiber-based network within the fracturing fluid that decouples proppant settling from fluid viscosity. This network entangles proppant, dramatically reduces proppant settling, and provides a mechanical means to transport and place the proppant at greater distances from the wellbore. An additional advantage of the new system lies in fiber degradability, which leads to a nondamaged fracture conductivity with time. Fluid rheology of fiber-laden fluids was measured over a 150-230 °F temperature range under various fiber loadings. Studies showed that under bottomhole temperature and fluid pH fiber decompose and form a water-soluble species. During fiber degradation, the permeability of the fiber-laden system approaches the value of permeability for the baseline system without fiber. Compatibility study of the degradation byproducts with formation water showed no precipitate formation in high salinity environments. The results demonstrate that the new fiber technology ensures uniform proppant placement within a long fracture, provides permeability equal to pure proppant pack values, and offers higher production rates in comparison with conventional fracturing treatments. Introduction Tight-gas formations are characterized by very low permeability values, usually in the range of micro- or nanodarcies. Long effective fracture half-lengths are required to optimize production rates and ultimate recovery in these formations. Good proppant placement throughout the payzone is very important, and minimizing height growth into unproductive adjacent layers significantly improves the economics of the fracturing treatment. Due to the high flow velocities in the propped hydraulic fracture in tight gas formations, there is an additional requirement to minimize non-Darcy flow effects and multiphase flow effects-commonly addressed using round, spherical proppants strong enough to withstand the effective stress in the fracture. All these requirements could be fulfilled by fracturing with low viscosity fluids if it were not for rapid proppant settling. Proppant settling, or even worse proppant settling out of the payzone, severely limits the effective fracture length. Inability of low viscosity fluid to carry proppant for extended periods at bottomhole temperature leads to a full proppant settling before the fracture closes. Poor carrying properties of such fluids result in poor vertical coverage of the fracture with proppant and therefore non-optimal fracture conductivity. Summarizing the aforementioned, the following general requirements for fracturing tight-gas formations could be defined:Create maximal effective fracture half-length Contain fracture height within pay zone Maximize fracture conductivity using correct proppant and clean fluids Ensure both good vertical coverage and deep placement of the proppant within the fracture. One of the existing ways to minimize particle settling during hydraulic fracturing is to use high concentration polymer crosslinked fluids having excellent proppant transport characteristics. However, being highly viscous, the crosslinked fluids can break out of zone. Furthermore, the high polymer concentration may cause irreparable damage to fracture conductivity. These two factors make this methodology inefficient in formations with extremely low permeability (microdarcies or less).
Few studies have dealt with the flow behavior of concentrated suspensions or slurries prepared with non-Newtonian carrier fluids. Therefore, the purpose of this investigation is to present experimental results obtained by pumping various hydraulic fracturing slurries into a fracture model and gathering data on differential pressure vs. flow rate. Several concentrations of hydroxypropyl guar (HPG), a wide range of proppant concentrations, and three test temperatures were studied. The effects of such variables as polymer gelling-agent concentration, proppant concentration, test temperature, and fracture-flow shear rate on the rheological properties of slurries were investigated. The correlations for predicting the relative slurry viscosity for these HPG fluids are presented. Substantial increases in viscosity of fracturing gels were observed, and results are discussed in light of several affecting variables. Results also are compared with those available for Newtonian and non-Newtonian concentrated suspensions. Application of these correlations to estimate the hindered particle-settling velocity in the fracture caused by the presence of surrounding particles also is discussed. The correlations presented can easily be included in any currently available 2D or 3D fracture-design simulators; thus, the information can be applied directly to predict fracture geometry and extension.
During the hydraulic-fracturing process, viscous fluid often is pumped down the well under high pressure to initiate and extend induced fractures. After this stage, another viscous-fluid stage containing proppant is pumped to maintain the fracture geometry created by the previous clean viscous-fluid stage. The other function of the proppant-laden fluid stage is to keep the created fracture open after pumping stops.
Fracture geometry and extension during treatment depend largely on the rheological properties of the clean and proppant-laden fluids. Proppant settling and distribution in the fracture also are affected significantly by slurry rheology. Rheological characterization of clean fluid (i.e., fluid without proppant) is relatively well-addressed. However, the rheological characterization of proppant-laden fracturing fluids or slurries is not well-investigated currently.