Channel fracturing combines geomechanical modeling, intermittent proppant pumping and degradable fibers and fluids to attain heterogeneous placement of proppant within a hydraulic fracture. The aim of this well stimulation technique is to promote the formation of stable voids or streaks within the proppant pack which serve as highly conductive channels for transport of oil and gas throughout the hydraulic fracture.More than 10,000 channel fracturing treatments have been performed in over 1,000 wells during the last three years in shale-, carbonate-, and sandstone-rich reservoirs worldwide. The collective dataset on job execution and well performance shows the following trends: (a) low occurrence of near wellbore screen-outs (>99.9% of all treatments achieving 100% proppant placement); (b) reduction in the amount of proppant required to complete treatments (in average, 43% less proppant than conventional techniques aiming at placing a homogeneous proppant pack as implemented in offset wells); (c) average initial and long-term well productivity and flowing pressures consistently meeting or exceeding those of wells completed with conventional fracturing techniques. This paper summarizes findings from a comprehensive technical study focused on ascertaining the enabling mechanisms for these trends. Results from laboratory experiments (large-scale slot flow, conductivity, proppant settling), yard tests (well site delivery characteristics, proppant slug integrity), and well performance evaluations (surface treatment data, well production data and reservoir simulations supported by history matching) are analyzed collectively to reach the following assessments: (a) heterogeneous proppant placement is achieved; (b) the low incidence of screen-outs is the result of the combination of reduced usage of proppant and intermittent pumping of proppant-free, fiber-laden slugs ("sweeps") which mitigate accumulation of proppant in the near-wellbore area; (c) well productivity trends are driven by the concomitant occurrence of enhanced fracture conductivity -enabled by the presence of heterogeneities within the proppant pack-and the development of larger fractured area within the reservoir effectively contributing to production. The development of larger effective contact area is enabled by the use of fibers, which enhance proppant transport within the fracture and mitigate proppant settling.
Increased drilling of infill wells in the Bakken has led to growing concern over the effects of frac or fracture hits between parent and infill wells. Fracture hits can cause decreased production in a parent well, as well as other negative effects such as wellbore sanding, casing damage, and reduced production performance from the infill well. An operator had an objective to maximize production of infill wells and decrease the frequency and severity of frac hits to parent wells. The goal was to maintain production of the parent wells and avoid sanding, which had the potential to cause cleanouts. Infill well completion technologies were successfully implemented on multiwell pads in Mountrail County, Williston basin, to minimize parent-child well interference or negative frac hits on parent wells for optimized production. Four infill (child) wells were landed in the Three Forks formation directly below a group of six parent wells landed in the Middle Bakken. The infill well completion technologies used in this project to mitigate frac hits included far-field diverter, near-wellbore diverter, and real-time pressure monitoring. The far-field diverter design includes a blend of multimodal particles to bridge the fracture tip, preventing excessive fracture length and height growth. The near-wellbore diverter consists of a proprietary blend of degradable particles with a tetra modal size distribution and fibers used to achieve sequential stimulation of perforated clusters to maximize wellbore coverage. Hydraulic fracture modeling with a unique advanced particle transport model was used to predict the impact of the far-field diverter design on fracture geometry. Real-time pressure monitoring allowed acquisition of parent well pressure data to identify pressure communication or lack of communication and implement mitigation and contingency procedures as necessary. Real-time pressure monitoring was also used to optimize and validate the far-field diversion design during the job execution. The parent well monitored was 800 ft away from the closest infill well and at high risk for frac hits due to both the proximity to the infill well and depletion. In the early stages of the infill well stimulation, an increase in pressure up to 600 psi was observed in the parent well. The far-field diverter design was modified to combat the observed frac hit, after which a noticeable drop in both frequency and magnitude of frac hits was observed on the parent well. This is the first time the far-field diverter design optimization process was done in real time. After the infill wells stimulation treatment, production results showed a positive uplift in oil production for all parent wells at an average of 118%. Also, only two out of seven parent wells required a full cleanout, resulting in savings in well cleanup costs. Infill well production data was compared with the closest parent well landed in the same formation (Three Forks). At about a year, the best infill well production was only 10% less than the parent well with similar completion design and the average infill well production approximately 18% less than the parent well. Considering the depletion surrounding the infill wells, production performance exceeded expectations.
Guar-based crosslinked fluids remained the prevalent choice of frac fluid for a long period of time, since massive hydraulic fracturing was started in Russia. Traditional frac fluid contains 2535 ppt of crosslinked guar, which results in very high fluid viscosity (min 400 cp at 100 sec-1 as rule of thumb) and low retained permeability of proppant pack - around 35%. With recent move towards complex geology reservoirs in Russia, where wide propped frac is no longer an optimum solution, the need in review of current fracturing approaches emerged. In several last years local operators started to gradually move away from h igh-viscosity fluids via its partial replacement with cleaner guar-based low viscous linear gel. However, even in this case retained fracture conductivities are typically not higher than 60-70%, especially in cases when hybrid fluid systems are used - linear fluid combined with crosslinked gel. Goal to reach improved fracture conductivity opens a field for new discoveries. This study objective is to evaluate the applicability of novel clean frac fluid for conventional reservoirs in Russia. Current study is focused on development of laboratory testing procedures and testing results analysis of novel synthetic polymer-based fracturing fluid in terms of its applicability on conventional reservoirs - tight sandstones. Viscous slickwater has already been widely used on shale reservoirs in North America, however was never applied for conditions of sandstones fracturing: in mili Darcy environment, in combination with ceramic proppant, pumping via tubing, utilizing pump rates less than 10 m3/min (60 bbl/min). Fluid rheology studies, leak-off behavior, regained conductivity of the proppant pack, regained permeability of the formation, dynamic proppant transport tests and dynamic fluid viscosity evaluation are described in the paper. Elastic properties of viscous slickwater (H.Zhao, S.Danican, H.Torres, Y.Christianti, M.Nikolaev, S.Makarychev-Mikhailov, A.Bonnell, Schlumberger, 2018) provide improved dynamic proppant transport and static proppant settling, in comparison with low viscous fluid - linear guar-based gel, i.e. better horizontal and vertical proppant distribution inside the fracture. Ceramic proppant pack conductivity even with high loadings of High Viscosity Friction Reducer without breakers showed superior results - Regained conductivity reached 100%. Coreflow experiments using conventional (1-10 mD) sandstone cores demonstrated 100% regained phase permeability to hydrocarbon, proving that fluid is non-damaging to formation. As a result of numerous laboratory studies performed, Viscous slickwater was qualified as alternative fracturing fluid to conventionally used guar-based gel and has been approved for field testing campaign on conventional tight sandstones in Russia. Field trials of novel frac fluid - Viscous slickwater demonstrated positive results both in terms of pumpability and well productivity on tight sandstones 0.5-3.0 mD This fluid has been recommended for further roll out to wider range of conventional oilfields.
scite is a Brooklyn-based organization that helps researchers better discover and understand research articles through Smart Citations–citations that display the context of the citation and describe whether the article provides supporting or contrasting evidence. scite is used by students and researchers from around the world and is funded in part by the National Science Foundation and the National Institute on Drug Abuse of the National Institutes of Health.
hi@scite.ai
10624 S. Eastern Ave., Ste. A-614
Henderson, NV 89052, USA
Copyright © 2024 scite LLC. All rights reserved.
Made with 💙 for researchers
Part of the Research Solutions Family.