Estimating the effective permeability and microfracture (MF) conductivity for unconventional reservoirs can be challenging; however, a new method for estimating using a stochastic approach is discussed. This new analysis method estimates matrix permeability and the unpropped and propped MF conductivities during laboratory testing where MFs were propped with ultrafine particles (UFPs). Kinetic Monte Carlo (KMC) simulations form the basis of the method used to estimate effective permeability of the core sample. First, the stochastic model was implemented to calculate effective matrix permeability of a small core taken from unfractured Eagle Ford and Marcellus formation samples using scanning electron microscopy (SEM) images and adsorption data to obtain the pore-size distribution (PSD) within the sample. The KMC approach then evaluated the effect of various parameters influencing the conductivity of laboratory-created MFs. Case studies considered for this work investigate the conductivity improvement of a manmade MF as a function of the UFPs used as proppants that maintain width under high stress, the UFP (proppant) concentration, and the UFP flow perpendicular into a secondary or adjacent MF zone (2ndMF) penetrating the face of an opened MF during flow testing under stress. The leakoff area widths considered were 1, 2, and 3 mm and can be propped or unpropped. Results obtained for the unfractured Eagle Ford and Marcellus samples closely correlate with other computational and experimental data available. For the laboratory-prepared nonpropped and propped MF samples, the effective propped width was determined to have the greatest effect on the MF conductivity, which increased by two orders of magnitude in the presence of the UFPs. The remaining two factors—proppant concentration and length of 2ndMFs—helped improve the effective MF conductivity in a linear manner; the highest proppant concentration and the 2ndMF zone resulted in the highest fracture conductivity achieved. Insight obtained from this study can be used to optimize fracturing designs by including UFPs and to create strategies for maximizing hydrocarbon recovery during development of unconventional resources where MFs are opened during stimulation treatments.
Various methods are used to overcome choking effects in propped fractures to enhance and maintain well productivity (particularly in low-permeability reservoirs). Choking effects can result from permeability damage caused by fracturing gel residues, low-proppant concentrations, proppant crushing from high closure stresses or use of low-quality fracturing sand, or embedment/intrusion of formation materials into the proppant pack. This paper describes the development and field applications of a new well stimulation method for generating stable and highly conductive channels within a propped fracture to help maximize the transport capability of hydrocarbons from the formation reservoir to the wellbore. Extensive laboratory experiments and large-scale testing were performed to evaluate the formation and stability of proppant aggregates and proppant-free channels (PFCs). Proppant-laden slurry (prepared by mixing fracturing sand coated with an agglomerating agent in a gel fluid) and crosslinkable proppant-free spacer fluid were pulsed intermittently to form proppant aggregated masses surrounded by proppant-free gel slugs. Highly conductive channels were formed surrounding the proppant aggregates after crosslinked gel slugs were broken and removed from the propped fracture, leaving behind proppant aggregated masses that supported the closed fracture. Field trials were performed in unconventional and conventional oil formations. Injection pressures of proppant-laden slurry and proppant-free spacer using the pulsing approach were found to be significantly lower than those applied with conventional hydraulic fracturing treatments, indicating this new method helps alleviate the risks of screenout, as the proppant-free spacer sweeps and mitigates the proppant buildup in the near-wellbore (NWB) area. Field results showed production in wells treated with the proppant-free channel fracturing method increased significantly, even using 40% less total proppant, compared to production of offset wells in which conventional fracturing treatments were performed.
Advancements in diversion technology in recent years have made horizontal, multistage fracturing more reliable. Diversion treatments help generate and maintain complexity within generated fracture networks and can lead to more thorough reservoir stimulation. This facilitates maximized stimulation volumes and, potentially, increased production. With industry accepted benefits of the method, diversion technologies have been applied in both primary and refracturing operations. Even with broad adoption of fluid diversion techniques, limited reports of dynamic testing of diversion processes or chemicals under laboratory conditions exist. This paper describes a laboratory testing apparatus designed to dynamically probe the underlying mechanistic and chemical variables that influence near wellbore diversion against a consolidated proppant pack. This apparatus allows some of the critical parameters of diversion to be evaluated independently. In this study, early steps were taken to gain some understanding of the contributing parameters, such as diverter concentration, temperature, and pressure, and how they may influence diverter effectiveness. The laboratory setup in this study aims to conceptualize near wellbore diversion against a consolidated proppant pack with the ultimate goal of expanding the methodology to simulate real-life operation of a diversion treatment on fractures. This apparatus can help determine effects of chemical components and size distribution during successful diversion placement. In addition, some of the effects of temperature, pressure, and flow rates on diversion operations are presented. This dynamic study of diverters provided more insight into understanding factors that affect diversion, and provided data that can help optimize future diversion treatments. It is widely acknowledged that diversion technology has significant impact in fracturing applications. By initiating the development of a viable lab scale apparatus for diversion chemical testing, greater understanding of how to implement optimized chemical formulations and engineering methods for more effective fluid diversion operations can be gained.
Conventional guar borate systems have historically been preferred for hydraulic fracturing applications because of the lower cost of the base polymer and crosslinker. Additionally, the fluid formulations can be easily tailored based on reservoir conditions and operational needs and the favorable tubular friction reducing characteristics of guar-based fluid systems makes them a desirable option for fracturing fluid systems. However, water insoluble residue resulting from guar-based systems may significantly impact the permeability of the proppant pack when flowing back and producing the well. A recently developed, nearly residue-free (RF) fluid system offers excellent cleanup properties and, as a result, has provided significantly improved production of hydrocarbons compared to typical guar-borate systems. While offering excellent performance and production, the RF fluid demonstrated significantly less friction reduction than comparable guar-based systems. This paper introduces a newly developed fluid system offering equivalent cleanup properties and performance, but with significantly enhanced friction reduction. The lower friction of the (LF)-RF system helps lower wellhead pressures to allow maintaining pump rate, adhering to the job design, to place the desired amount of proppant in the fracture. This newly developed LF-RF fluid is a high performance fracturing fluid with improved regained conductivity and core permeability cleanup compared to typical guar-borate crosslinked systems. It is applicable within a wide variety of reservoirs, including unconventional reservoirs, and to-date has been successfully used in more than 1,100 stages since its introduction in early 2014. The LF-RF fluid system is applicable from 100 to 275°F bottomhole static temperature (BHST) and offers excellent operational versatility and proppant transport. This paper compares fluid performance and friction response of a conventional guar-borate fluid and the existing RF system with the newly developed LF-RF fracturing fluid.
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