Production interference between parent and infill wells has become of utmost importance in unconventional reservoirs across the U.S. due to sub-par production performance of child wells as well as possible loss of production to the parent well. To mitigate production interference between parent and child wells, operators have applied various measures such as refracturing, repressurization of the parent well, and reducing child well stimulation jobs; these measures can be costly and yield mixed results. This study demonstrates the benefits of reservoir modeling to understand the effects of parent well production depletion on child wells at different well spacing as well as the use of successful mitigation strategies such as near-wellbore diverters and fracture geometry control to mitigate frac hits between wells drilled as close as 800 ft apart. A multidisciplinary integrated workflow was applied in a multiwell pad in the Bakken consisting of one parent and two child wells. The parent well was completed and produced for about 7 years, after which the two child wells were drilled 1,300 and 800 ft, respectively, on each side of the parent well. High-tier vertical logs were used to build a geomechanical and petrophysical model for the pad. The model was used for hydraulic fracture modeling and production history match of the parent well, after which the reservoir pressure depletion profile was used in a geomechanics simulator for an updated in situ stress state at 7 years. The updated stress state was then used for fracture modeling of the two child wells. The child well 800 ft from the parent well showed more hydraulic fractures directly hitting the parent well. The child well at 1,300 ft showed fewer hydraulic fractures directly hitting the parent well. The pressure depletion profile around the parent well had more negative impact on the child well at 800 ft away compared to the child well at 1,300 ft away because of its proximity. To eliminate this negative effect, fracture geometry control technology was used in the hydraulic fracture model for the child well 800 ft away from the parent well. It showed to be successful in reducing the occurence of frac hits to the parent well, diverting hydraulic fracture growth away from depleted regions around the parent well. During the actual operation, the results were confirmed with high-frequency pressure monitoring. Details of the field deployment of the fracture geometry control technology are discussed in detail in Vidma et al. (2019). No pressure communication was observed in stages pumped with the fracture geometry control technology. The child wells were completed and put on production without any sanding damage to the parent well, saving the operator approximately USD 400,000 and more than 2 weeks of deferred production if cleanout had been required. Actual production results showed superior performance in the child well at 1,300 ft away compared to the child well at 800 ft away. This confirms that the pressure depletion profile had more impact on the child well 800 ft away compared to the child well at 1,300 ft. Reservoir modeling is critical to understanding the level of pressure depletion in a producing well and its effect on child wells at different well spacing. It has also proven helpful in designing an optimum fracture geometry control pill to minimize the occurrence of frac hits that could damage parent well productivity.

More than 60% of US land wells drilled in 2017 are infill wells. Fracturing in such wells is likely to cause fracture hits on adjacent wells, which may have a negative impact on the infill and nearby existing well production. A new technology has been developed to control the geometry of the fracture, which reduces significantly the fracture hit rate and increases production in the child (infill) and parent wells. Traditional methods for controlling the geometry of hydraulic fractures include adjusting pad and proppant volumes and fluid viscosity. The proposed technology uses an alternative approach, delivering a multimodal particulate diversion mix with the proppant. The job is designed so that the diversion mix bridges and accumulates at the fracture tip, thus confining the fracture perimeter and controlling fracture length growth. The proposed technology has been field tested in 11 wells (219 stages) in the Eagle Ford shale. The results showed high efficiency of fracture hit prevention (84% of stages free of fracture hits) and increased production in the child and parent wells. The technology showed high operational reliability, (no premature screenouts) and was proven to be cost effective and robust. Laboratory experiments were conducted to tailor the permeability of the diversion blend. Because the diversion blend contains very small particulates, a wellsite delivery method was developed to prepare the blend and deliver it safely. Guidelines for the diverting pill pumping schedule were developed to optimize fracture hit prevention. The developed technology demonstrates that the complicated process of fracture growth geometry correction can be performed with intelligent engineering design including a far-field diversion pill.

The increasing trend of drilling infill wells (more than 60% of new wells in 2017) comes with the significant risk of well interference, or "frac hits". Frac hits occur during hydraulic fracturing operations when there is direct pressure communication between the well being treated and adjacent, pre-exisiting wells. In extreme cases, the fracture may fill the adjacent wellbore with sand, which requires expensive cleanup intervention. Fracture geometry control technologies aim to reduce the likelihood of well interference by deploying far-field diversion techniques. This paper presents a unique field experiment that demonstrates the value and effectiveness of these technologies. In the Bakken, two child wells were drilled 1,300 and 800 ft, respectively, on each side of an existing, partially depleted parent well. Each child well treatment comprised 50 stages of slickwater, completed in zipper frac style. Treatments in the farther well did not utilize any fracture geometry control technology. In the nearer well, 20 of 50 stages (one every 5 stages) included far-field diversion material. All other parameters of the pumping schedules were the same between the two treated wells. Pressures were monitored in all three wells (parent and two child wells) at high frequency during all operations. The parent well was not damaged during the operation. However, during the first 35 stages of the child well treatments, the parent well's pressure increased in spurts, until it stabilized near expected reservoir pressure. In this paper, each instance of well interference is quantified and attributed to a treatment stage in one of the child wells. Interestingly, not all stages contributed to the pressure buildup. Significantly, various levels of frac hits were observed, as determined by the magnitude and steepness of the pressure increase. The correlation of frac hit with the absence of far-field diverter is striking. The results clearly demonstrate that fracture geometry control technologies reduce the occurrence of direct well interference by containing fracture growth. The operations in these wells created a unique opportunity to design a field experiment to assess the effect of fracture geometry control technology on well interference during infill well stimulation. The results demonstrate that such technologies reduce the occurrence of direct frac hits in depleted parent wells.

No abstract

In water injector wells, continuous injection can wash gravel from the annulus around the screen, especially if the rate of injection generates a pressure above the fracture threshold. The voids created after the washout are sometimes filled by an influx of formation sand during shut-in operations. This sand accumulation consequently reduces the injectivity when the injection operations resume. A solution to prevent such washouts is needed to maintain sand control and injectivity throughout the life of water injector wells. As a solution to this common problem, we propose a new fiber based product that reinforces the gravel and/or proppant pack. The fibers have an outside layer that is activated by temperature to form a bonded fiber network that locks the gravel in place. The fibers can be used with any type and size of proppant. The key benefit is that the fibers can withstand the cyclic loading of stress inherent to the shut-in and restart of injection operations, which are typically performed several hundred times during the life of an injector well. Our experimental study showed that the drag force of injected water easily displaced the gravel in the annulus into the fracture, whereas when gravel is reinforced with the fibers it withstood the drag force even at high injection rates (e.g., at 100 B/D per 0.5-in.-diameter perforation). We performed several experiments to evaluate the strength of the pack under cyclic stress conditions. After 30 cycles, the pack strength remained unaffected. The fiber chemistry was tailored for compatibility with commonly used fracturing fluids and brines. We found that the fibers remained connected in an interconnected network even after long-term interaction with seawater. We also studied the interaction of fibers with screens and other downhole equipment that comes in contact with the fibers during gravel placement. The laboratory results of that study showed the fibers do not create any issues with proppant placement or tool functionality during the sand control operation. Our experimental study also showed the fibers provided an effective solution for preventing gravel washout in water injector wells, thereby supporting the sand control and injectivity for the life of the well.