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The use of high viscosity friction reducers (HVFR) as alternatives to guar-based fluids to improve proppant transport and lessen formation damage has increased rapidly. While several product options are available, the criteria for selection of a product has focused on viscosity at 300 RPM (511s-1) that meets or exceeds that of linear gel fluids. However, there has been limited data available on what the target viscosity should be, how it influences the fluid's ability to transport sand, and the potential for damage to proppant conductivity. This study presents methodology used to screen HVFR's and results on product performance, which identified a need for alternative specifications to viscosity to achieve maximum performance.
The proppant transport capacity in dynamic conditions was evaluated for twenty-eight commercially available friction reducers and HVFR's in field waters which could have up to 40,000 TDS. A slot flow apparatus was used to mimic fluid flow through a fracture under different shear and flow rate conditions. Viscosity and elasticity measurements were also obtained using an advanced rotational rheometer. For comparison, linear gel and crosslinked guar fluid were also evaluated.
While viscosity at 300 RPM (511s-1) and more recently high viscosity at lower shear rates, have been used for selection of HVFR's, these parameters alone do not indicate proppant carrying capacity. The authors did not find a correlation between higher viscosity and better proppant transport, rather they propose that too high a viscosity can negatively impact transport. The results provided insight into the effect of flow rate on proppant transport, with some HVFR's that exhibited higher viscosities at low shear, losing their transport capacity at the same low shear. Elasticity testing of those same products suggested that HVFR's have a critical elasticity range at which they will provide optimal performance. Polymer residuals were also evaluated on proppant post-test and compared to traditional linear gels and crosslinked fluids. Results suggested potential for damage if HVFR's are used without breakers. Different viscosity targets should be set when selecting a HVFR and coupled with other testing criteria such as elasticity and dynamic proppant transport.
This paper provides insight into the need for development of standardized test criteria for HVFR selection. Further testing and screening of HVFR's will help increase the understanding of key factors influencing sand transport and their effect on proppant pack conductivity.
The primary purpose of using traditional friction reducers in stimulation treatments is to overcome the tubular drag while pumping at high flow rates. Hydraulic fracturing is the main technology used to produce hydrocarbon from extremely low permeability rock. Even though slickwater (water fracturing with few chemical additives) used to be one of the most common fracturing fluids, several concerns are still associated with its use, including usage of freshwater, high-cost operation, and environmental issues. Therefore, current practice in hydraulic fracturing is to use alternative fluid systems that are cost effective and have less environmental impact, such as fluids which utilize high viscosity friction reducers (HVFRs), which typically are high molecular weight polyacrylamides. This paper carefully reviews and summarizes over 40 published papers, including experimental work, field case studies, and simulation work. This work summarizes the most recent improvements of using HVFR’s, including capability of carrying proppant, reducing water and chemical requirements, its compatibility with produced water, and environmental benefits in hydraulic fracturing treatments. A further goal is to gain insight into the effective design of HVFR based fluid systems.
The findings of this study are analyzed from over 26 field case studies of many unconventional reservoirs. In comparing to the traditional hydraulic fracture fluids system, the paper summaries many potential advantages offered by HVFR fluids, including: superior proppant transport capability, almost 100% retained conductivity, cost reduction, minimizing chemicals usage by 50%, less operating equipment on location, reducing water consumption by 30%, and fewer environmental concerns. The study also reported that the common HVFR concentration used was 4gpt. HVFRs were used in the field at temperature ranges from 120°F to 340°F. Finally, this work addresses up-to-date challenges and emphasizes necessities for using high viscosity friction reducers as alternative fracture fluids.
Using optical fibers to instrument hydraulically fractured wells is becoming routine in US unconventional plays. Instrumented wells facilitate understanding of proppant distribution among perforation clusters and the inefficiencies of geometric fracturing and well planning techniques. However, converting fiber-optic data into proppant distribution requires management of high volumes of data and correlation of the data to factors such as well conditions, fracturing parameters, and temperatures. A user-friendly workflow for understanding hydraulic fracturing proppant and slurry distribution among different perforation clusters over time is presented. Ideally, slurry flow is equal between perforation clusters and, at least, constant in time, but the reality is very different. The interpretation workflow is based on proprietary algorithms within a general wellbore software platform and aims to greatly expedite the analysis. We propose using distributed acoustic sensing (DAS) data (in the form of custom frequency band energy (FBE) logs), distributed temperature measurements (DTS) and surface pumping data to obtain a quantitative analysis of proppant distribution within minutes, with various options for reporting and visualizing results. The software platform selected provides data integration, visualization, and customization of in-built algorithms. The new workflow enables users to upload DAS, DTS, flow rate, pressure, and other measurements and use customized algorithms to quantitatively analyze proppant distribution, enabling decisions in real time to optimize the fracturing operation. The validity of the approach is illustrated by a case study involving a well with 28 stages and four to five clusters per stage. The workflow is automated to provide results in real time, enabling quick corrective actions and significantly improving the efficiency and economics of hydraulic fracturing.
The recent and rapid success of using high viscosity friction reducers (HVFRs) in hydraulic fracturing treatments is due to several advantages over other fracture fluids (e.g. linear gel), which include better proppant carrying capability, induce more complex fracture system network with higher fracture length, and overall lower costs due to fewer chemicals and less equipment on location. However, some concerns remain, like how HVFRs rheological properties can have impact on proppant transport into fractures. The objective of this study is to provide a comprehensive understanding of the influence the rheological characterization of HVFRs have on proppant static settling velocity within hydraulic fracturing process. To address these concerns, comprehensive rheological tests including viscosity profile, elasticity profile, and thermal stability were conducted for both HVFR and linear gel. In the steady shear-viscosity measurement, viscosity behavior versus a wide range of shear rates was studied. Moreover, the influence of elasticity was examined by performing oscillatory-shear tests over the range of frequencies. Normal stress was the other elasticity factor examined to evaluate elastic properties. Also, the Weissenberg number was calculated to determine the elastic to viscous forces. Lastly, quantitative and qualitative measurements were carried out to study proppant settling velocity in the fluids made from HVFRs and linear gel. The results of rheological measurement reveal that a lower concentration of HVFR-2 loading at 2gpt has approximately more than 8 times the viscosity of linear gel loading at 20ppt. Elastic measurement exposes that generally HVFRs have a much higher relaxation time compared to linear gel. Interestingly, the normal stress N1 of HVFR-2, 2gpt was over 3 times that of linear gel loading 20ppt. This could conclude that linear gel fracture fluids have weak elastic characterization compared to HVFR. The results also concluded that at 80 C° linear gel has a weak thermal stability while HVFR-2 loses its properties only slightly with increasing temperature. HVFR-2 showed better proppant settling velocity relative to guar-based fluids. The reduction on proppant settling velocity exceed 75% when HVFR-2 loading at 2gpt was used compared to 20ppt of linear gel. Even though much work was performed to understand the proppant settling velocity, not much experimental work has investigated the HVFR behavior on the static proppant settling velocity measurements. This paper will provide a better understanding of the distinct changes of the mechanical characterization on the HVFRs which could be used as guidance for fracture engineers to design and select better high viscous friction reducers.
This paper presents a data driven approach to answer the question of whether premium, high strength white sand proppant, while more expensive than regional (brown) sand, is justified due to its alleged ability to make better producing wells. For this study, 739 horizontal wells with production, and stimulation data were used in a robust statistical approach to conclude that, for the most common set of well characteristics, white sand will produce a superior NPV weighted economic outcome than lower cost regional (brown) sand alternatives. While there are wells in this analysis that did not produce this robust conclusion of "white sand is better", none of them produced an outcome that "brown sand was better". Rather, several of the wells simply had results that were statistically inconclusive. This paper serves as a good example of what data are needed to perform such an analysis and the challenges of normalizing'first order effects' that dominate the influence on well productivity (TVD, lateral length, and proppant intensity) while attempting to ascertain the influence of'second order' factors such as Sand Type. Becoming familiar and adept at these analysis methods should facilitate the statistical verification of other second order effects on finding the optimal stimulation treatment.
High viscosity friction reducers (HVFRs) are an important component of slickwater hydraulic fracturing applications. To continue to treat multiple clusters effectively within longer laterals, even for stages near the toe area, a high molecular weight HVFR polymer, such as polyacrylamide, is commonly used to overcome pipe friction at 1 gal/Mgal or lower. To carry proppant into fractures, it is commonly assumed that the higher viscosity the HVFR yields, the better the proppant transport, necessitating higher HVFR concentrations than 1 gal/Mgal. However, a field study within the Anadarko Basin demonstrates that viscosity is not necessarily the best indicator of how efficiently HVFRs carry proppant. Instead, HVFR elasticity might play a more important role during proppant transport. Secondly, HVFRs concentration of 1 gal/Mgal or higher could potentially plug the proppant pack or form a filter cake on the rock surface, causing formation damage. Although previous laboratory methods to determine potential formation damage exist, results are difficult to correlate with field applications; hence, the conclusions remain elusive. A relatively new analysis procedure yielding improved assessments of residual HVFR concentrations for both flowback and produced waters, which aid understanding potential formation damage after hydraulic fracturing, is discussed.
Xu, Zhengming (China University of Petroleum, Beijing) | Wu, Kan (Texas A&M University) | Song, Xianzhi (China University of Petroleum, Beijing) | Li, Gensheng (China University of Petroleum, Beijing) | Zhu, Zhaopeng (China University of Petroleum, Beijing) | Sun, Baojiang (China University of Petroleum, East China)
Energized fracturing fluids, including foams, carbon dioxide (CO2), and nitrogen (N2), are widely used for multistage fracturing in horizontal wells. However, because density, rheology, and thermal properties are sensitive to temperature and pressure, it is important to understand the flow and thermal behaviors of energized fracturing fluids along the wellbore. In this study, a unified steady-state model is developed to simulate the flow and thermal behaviors of different energized fracturing fluids and to investigate the changes of fluid properties from the wellhead to the toe of the horizontal wellbore. The velocity and pressure are calculated using continuity and momentum equations. Temperature profiles of the whole wellbore/formation system are obtained by simultaneously solving energy equations of different thermal regions. Temperature, pressure, and energized-fluid properties are coupled in both depth and radial directions using an iteration scheme. This model is verified against field data from energized-fluid-injection operations. The relative average errors for pressure and temperature are less than 5%. The effects of injection pressure, mass-flow rate, annulus-fluid type, foam quality, and proppant volumetric concentration on pressure and temperature distributions are analyzed. Influence degrees of these operating parameters on the bottomhole pressure (BHP) for different energized fracturing fluids are calculated. The required injection parameters at the surface to achieve designed bottomhole treating parameters for different energized fracturing fluids are compared. The results of this study might help field operators to select the most-suitable energized fluid and further optimize energized-fluid-fracturing treatments.
Viscoelastic surfactants (VES) are important gelling agents in well stimulation treatments. Proper job design requires that the additives create the desired viscosity for effective proppant or gravel pack sand transport. Post-stimulation production enhancement partially relies on the thoroughness of gelling agent destruction or removal, known as "breaking" the gel. VES gels are non-damaging and do not create a filter cake, and thus are prone to high leak-off. The leak-off fluid potentially has a high zero-shear viscosity and can be challenging to remove from the formation. We propose a breaker system that comprises a monomer and radical initiator that will travel into to the formation with the VES gel. The resulting polymer will disrupt the worm-like micelles of the VES, creating spherical micelles and reducing the viscosity of the fluid. The breaker system presented here is operable at 200 °F. Rheology measurements show that the VES fluid with monomer and initiator has reduced viscosity and becomes less shear-thinning. Optical transmission and backscattering measurements show that the presence of breaker does not greatly accelerate proppant settling. The reduced viscosity would not adversely affect proppant transport. Core flow experiments compared retained permeability of cores treated with VES and VES with reacted monomer and initiator. The core flushed with broken fluid possessed a retained permeability of 79%, while the unmodified VES left only 44% retained permeability.
Moore, Joseph (DowDuPont Industrial Biosciences) | Massie-Schuh, Ella (DowDuPont Industrial Biosciences) | Wunch, Kenneth (DowDuPont Industrial Biosciences) | Manna, Kathleen (DowDuPont Industrial Biosciences) | Daly, Rebecca (Colorado State University) | Wilkins, Michael (Colorado State University) | Wrighton, Kelly (Colorado State University)
Hydraulic fracturing presents an ideal breeding ground for microbial proliferation due to the use of large volumes of nutrient-rich, water-based process fluids. Bacteria and/or archaea, when left uncontrolled topside or in the reservoir, can produce hydrogen sulfide, causing biogenic souring of hydrocarbons. In addition, microbial populations emerging from the downhole environment during production can colonize production equipment, leading to biofouling, microbially influenced corrosion (MIC), produced fluid separation issues, and HS&E risks. Mitigating these risks requires effective selection and application of biocides during drilling, completion, and production. To this end, a microbiological audit of a well completion operation with the objective of determining the effectiveness of a tandem chlorine dioxide (ClO2) and glutaraldehyde/quaternary ammonium (glut/quat) microbial control program was carried out. This paper describes the rationale behind selection of sampling points for a comprehensive microbiological field audit and provides the resulting critical analysis of biocide efficacy in the field using molecular assays (qPCR, ATP) and complementary culturing techniques (microtiter MPN and culture vials—commonly termed "bug bottles").
Due to the comprehensive nature of sampling and data collection, it was possible to make much more applicable and relevant observations and recommendations than it would have been using laboratory studies alone. First, multiple sources of microbial contamination were identified topside, including source waters, working tanks, hydration units, and guar. Additionally, critical analysis of biocide efficacy revealed that ClO2 treatment of source water was short-lived and ineffective for operational control, whereas glut/quat treatment of fracturing fluids at the blender was effective both topside and downhole. Analysis of the microbial load at all topside sampling points revealed that complete removal of ClO2 treatment could be offset by as little as a 10% increase in glut/quat dosage at the blender. This is a highly resolved microbiological audit of a hydraulic fracturing opration which offers new, highly relevant perspectives on the effectiveness of some biocide programs for operational control. This overview of biocide efficacies in the field will facilitate recommendations for both immediate and long-term microbial control in fractured shale reservoirs.