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.
Zhao, Haiyan (Schlumberger) | Danican, Samuel (Schlumberger) | Torres, Hortencia (Schlumberger) | Christanti, Yenny (Schlumberger) | Nikolaev, Max (Schlumberger) | Makarychev-Mikhailov, Sergey (Schlumberger) | Bonnell, Andrew (Schlumberger)
The development of unconventional fields has experienced major efficiency gains. One main breakthrough in efficiency is the introduction of viscous slickwater fracturing fluids. Viscous slickwater enables placement of higher proppant concentration than conventional slickwater and is less damaging than guar-based fluid, leading to aggressive fracturing designs and improved production.
High viscosity friction reducer is the main component in viscous slickwater, which can replace hybrid and crosslinked fracturing fluids in unconventional reservoir completions. The successful application of high viscosity friction reducing fluid requires proper fluid hydration and adequate viscosity, which depends on water salinity and proppant concentration. We developed techniques for improved testing of friction reducers and friction reducer selection guidelines to support optimum placement of the fracturing design. A comparison of production results of wells fractured by viscous slickwater to those offset wells demonstrated the effectiveness of aggressive design with viscous slickwater fluids.
A high viscosity friction reducer was tested in the laboratory and applied in the field. Experimental data demonstrate a good correlation between low shear viscosity and proppant transport capability. Static and dynamic proppant transport data were used to design viscous slickwater to replace linear gel. The friction reducer has been successfully applied in the field in more than 3,000 stages. Formations that were traditionally fractured with crosslinked gel were successfully fractured using viscous slickwater with ease. Replacing conventional slickwater with viscous slickwater enables the transport of higher proppant concentration with little change in operations. Aggressive designs deliver a boost in production, thus confirming viscous slickwater as the fluid of choice.
Improved chemistry enables easier operations, faster well completion, and improved initial production, as confirmed by case studies. This study provides information for the application of viscous slickwater and the rigorous testing that is required and often overlooked.
Unconventional completions in North America have seen a paradigm shift in volumes of proppant pumped since 2014. There is a clear noticeable trend in both oil prices and proppant volumes – thanks to low product and service costs that accompanied the oil price crash in early 2015. As the industry continues to recover, operators are reevaluating completion designs to understand if these proppant volumes are beyond what is optimal. This paper analyzes trends in completion sizes and types across all major unconventional oil and gas plays in the US since 2011 and tracks their impact on well productivity.
Completion and production data since 2011 from more than 70,000 horizontal wells in seven major basins (Gulf Coast, Permian, Appalachian, Anadarko, Haynesville, Williston and Denver Julesburg basins) and 11 major oil/gas producing formations were analyzed to examine developments in proppant and fluid volumes. Average concentration of proppant per gallon of fluid pumped was used to understand transitional trends in fracturing fluid types with time. Production performance indicators such as First month, Best 3 or Best 12 months of oil and gas production were mapped against completion volumes to evaluate if there are added economic advantages to pumping larger designs.
In general, all major basins have seen progressive improvements in average well performance since 2011, with the Permian Basin showing the highest improvement, increasing from an average first-six-months oil production of 25,000 bbl in 2011 to 75,000 bbl in 2017. The Gulf Coast basin, where the Eagle Ford formation is located, has seen a 6-fold increase in proppant volumes pumped per foot of lateral since 2011 while the Permian and Appalachian basins hit peak proppant volumes in 2015 and 2016 respectively. In Permian and Eagleford wells, higher proppant volumes in general have resulted in better production up to a certain concentration. In Williston and Denver basins, most operators are moving away from gelled fluids, and reduced average proppant concentration per fluid volume pumped shows inclination toward hybrid or slickwater designs. While some of these observations are tied to reservoir quality, proppant volumes have begun to peak as operators have either reached an optimal point or are in the process of reducing volumes.
Demand for proppant is expected to nearly double by 2020. As oil prices continue to recover, well AFEs continue to increase, despite multiple efforts to improve capital efficiency. The need for enhanced fracture conductivity and extended half-lengths on EURs are been discussed by combining actual observed production data and sensitivities using calibrated production models. The industry is moving toward large-volume slickwater fracturing operations using smaller proppants, but he operating landscape is expected to see a correction when such designs become less economical.
This paper was prepared for presentation at the Unconventional Resources Technology Conference held in Houston, Texas, USA, 23-25 July 2018. The URTeC Technical Program Committee accepted this presentation on the basis of information contained in an abstract submitted by the author(s). The contents of this paper have not been reviewed by URTeC and URTeC does not warrant the accuracy, reliability, or timeliness of any information herein. All information is the responsibility of, and, is subject to corrections by the author(s). Any person or entity that relies on any information obtained from this paper does so at their own risk. The information herein does not necessarily reflect any position of URTeC. Any reproduction, distribution, or storage of any part of this paper by anyone other than the author without the written consent of URTeC is prohibited. Abstract Hydraulic fracturing is the method of choice for well stimulation in North America. Large-scale analysis of the effects of various well stimulation parameters on production is of great interest for elucidating production trends and treatment efficacy.
Abivin, Patrice (Schlumberger) | Prabhu, Rasika (Schlumberger) | Khvostichenko, Daria (Schlumberger) | Hilliard, Casie (The Dow Chemical Company) | Nelson, Chris (The Dow Chemical Company) | Kuo, Tzu-Chi (The Dow Chemical Company) | Li, Yongfu (The Dow Chemical Company) | Shukla, Priyavrat (Schlumberger) | Makarychev-Mikhailov, Sergey (Schlumberger)
This paper was prepared for presentation at the Unconventional Resources Technology Conference held in Houston, Texas, USA, 23-25 July 2018. The URTeC Technical Program Committee accepted this presentation on the basis of information contained in an abstract submitted by the author(s). The contents of this paper have not been reviewed by URTeC and URTeC does not warrant the accuracy, reliability, or timeliness of any information herein. All information is the responsibility of, and, is subject to corrections by the author(s). Any person or entity that relies on any information obtained from this paper does so at their own risk. The information herein does not necessarily reflect any position of URTeC. Any reproduction, distribution, or storage of any part of this paper by anyone other than the author without the written consent of URTeC is prohibited. Abstract The efficiency of hydraulic fracturing operations can be significantly impaired by multiple damage mechanisms induced by the fracturing fluid, that affect both the formation and the proppant pack. The two key damage factors are a) unbound immobile water trapped in pores preventing the flow of hydrocarbons and b) insoluble polymer residue originating from degraded fracturing fluid gelling agents.
A statistically rigorous assessment of the effect of fracturing treatment chemical additives on well productivity was performed. The dataset for analysis consisted of over 4,500 slickwater-treated wells in the lower 48 US states. All wells were treated by a single service company within a 5-year period. The analysis focused on two distinct additives, namely, linear guar gels and surfactant-based flowback aids, in slickwater treatments. A method and workflow to quantify the effects of completion parameters on well productivity were developed in this work. The statistical t-test was used to assess the statistical significance of differences in aggregated production metrics between datasets based on the observation that production data were distributed log-normally. The proposed workflow addresses many common issues a reservoir engineer faces during data sourcing, preprocessing, evaluation, and interpretation and further highlights the importance of proper statistical approaches. The analysis results emphasize the benefits of proper job design even in relatively simple slickwater treatments.
Vaidya, Nirupama (Schlumberger) | Lafitte, Valerie (Schlumberger) | Makarychev-Mikhailov, Sergey (Schlumberger) | Panga, Mohan Kanaka Raju (Schlumberger) | Nwafor, Chidi (Schlumberger) | Gadiyar, Balkrishna (Schlumberger)
Viscoelastic Surfactant (VES) fluids have been used in many openhole gravel packing applications with the shunt tube technique as they offer several advantages over polymeric fluids. However, existing VES fluids have temperature limitations. The objective of this work was to develop a new viscoelastic surfactant (VES) based fluid for gravel packing wells with temperature up to 325°F while retaining the advantages of existing VES fluids.
The new fluid system consists of a surfactant, a cosurfactant, and a nanoadditive. The performance of the new fluid system was evaluated in laboratory experiments up to 325°F. The properties studied and discussed in this paper are shear recovery time, rheology (viscosity versus shear rates), gravel suspension, and core retained permeabilities. The optimization of the final fluid formulation based on sensitivity of the target properties to concentration of each component is also detailed in the paper.
The new VES-based gravel pack carrier fluid incorporating a nanoadditive showed significantly improved performance at elevated temperatures compared with conventional fluids. In particular, while the conventional VES fluids do not meet the gravel suspension requirement, the new fluid system is able to suspend the gravel under static conditions up to 325°F. In addition, the viscosity at low shear rates is improved while the viscosity at high shear rates is comparable to existing VES fluids. Tests with outcrop cores of varying permeabilities demonstrated the fluid's minimal formation damage. The complete VES fluid system with nanoadditive was found to be compatible with both monovalent and divalent brines at densities up to 14.0 lbm/gal. As such, it is a more cost-effective alternative to xanthan-based carrier fluids, which are incompatible with inexpensive calcium brines and thus necessitate sodium bromide or formate brines depending on the density requirements. Based on the extensive laboratory study, it can be concluded that the new fluid system outperforms conventional VES gravel pack carrier fluids at high temperatures while retaining the benefits of the conventional VES fluids.
The new fluid system significantly extends the temperature limit of VES-based gravel packing carrier fluids. The fluid system can also be used with many completion brines and mixed at a wide density range, making it an excellent alternative to conventional polymeric fluids used in gravel packing applications.
Water produced during flowback and production operations may be one of the largest sources of untapped knowledge in hydraulic fracturing. This water, once in intimate contact with the reservoir, proppant pack, and tubulars, may contain a fingerprint reflective of damage related to polymer cleanup, propped pathway integrity, fines release, mineral scale precipitation, and bacterial activity. In cooperation with the operator, Lonestar Resources, of three Eagle Ford shale wells, we developed a workflow to characterize flowback water for indications of damage.
In this study, 50 produced water samples per well were collected for a three-well pad in Dimmit County, Texas, over the course of a year. Select samples were analyzed for up to 50 parameters. From this comprehensive laboratory survey, we determined 1) which methods yielded data least corrupted by interferences, 2) which practices preserved time-sensitive markers, and 3) which sample frequencies captured sufficient resolution of the downhole effects of interest. From these learnings, we developed a workflow to generate an appropriately scoped, high-quality dataset to facilitate interpretation of subsurface phenomena.
Several findings involved the measurement and analysis of guar, solids, salinity, scaling ions, and trace minerals. For example, although guar is present in high concentration initially, the concentration for all three wells declined to near-detection limits after several months, while water production continued. We hypothesize that the recovery of guar and its molecular weight distribution is indicative of the degree of cleanup from the proppant pack and may be useful for optimizing breaker design and flowback strategy for subsequent wells. Another finding was that salinity could be readily measured by a variety of simple and robust measurement techniques (i.e., conductivity, specific gravity, refractive index, etc.). Salinity, measured on a continuous basis through one of these robust techniques, may provide a unique way to observe shifts in producing zones due to failures related to pinch points. With a suite of chemical markers and the workflow to exploit them, produced water could be a valuable tool with which to monitor subsurface behavior, identify damage mechanisms, and ultimately improve completion practices.
Polymer gels used in hydraulic fracturing to generate fracture geometry and ensure proppant transport are also known to damage the proppant pack permeability, and this damage reduces the well production rate. As reuse of produced water and other highly saline water sources for fracturing applications grows, there is further damage expected from scale/precipitate deposition into the proppant pack. Past studies in the literature focus on impairment of proppant pack permeability from broken polymer gel residue, but precipitation of scale from source water is not considered. The objectives of this study are (i) to develop laboratory methods of assessing conductivity reduction from different fluid-based factors such as polymer residue and scale and (ii) to develop correlations to predict retained permeability based on simplified measurements. The simple methods will minimize the need for the standard conductivity testing, which can be time consuming, expensive, prone to significant test-to-test variation, and still subject to experimental artifacts. By the use of simplified procedures, the cost of conductivity testing can be reduced while allowing validation of the simplified method results.
We demonstrate a simple benchtop method to measure permeability of a proppant pack damaged by polymer residue, scale, or both. This method provides an opportunity to study a specific damage source in isolation, where the test is not influenced by problems such as spatial inhomogeneity of gel break, ineffective cleanup of filter cake, creation of proppant crush fines, etc., that are inherent in conventional API-type conductivity tests.
Experimental measurements of retained permeability arising from different sources such as polymer residue and scale were compared with traditional conductivity measurements. They were also correlated with empirical permeability models that rely on proppant pack porosity.
One key insight from the new, simplified method for proppant damage assessment is that the loss of permeability correlates with porosity reduction from polymer residue volume with a similar extension to scale precipitation.