Frac hits or "frac bashing" is a fracture-initiated well-to-well communication event that can create production losses (or gains), and on occasion, mechanical damage when frac energy from a stimulated well extends into the drainage area or directly contacts an adjacent or offset well. Pressure increases have been detected in wells at distances ranging from hundreds to thousands of feet from the stimulated well. While these in-zone frac hit events do not pose an environmental problem if there is no failure of containment, there can be some alteration of the production potential in one or both of the wells involved. Frac hits along the preferential fracture plane were an uncommon but known event when the completion method only involved vertical wells, but the rate of incidence has increased sharply as the preferred completion method has shifted to relatively closely-spaced, multiple fractured horizontal wells (MFHW) in low permeability formations such as the mudstone rocks commonly referred to as shales. Mechanical damage within the well and success of methods of prevention, damage control and remediation will be examined by case histories and published contexts of incidents in several basins, but will not be the main goal of the paper. The primary effort will focus on examining causes of production loss and duration of the loss, including looking at production declines pre-hit and post-hit. Known causes include in-situ stress alteration potential, timing of fracture closure, near-wellbore proppant loss, liquid loading, rock-fluid interactions, sludges and wetting factors. Also considered will be geological effects such as regional fractures and linked natural fracture clusters. A main objective will be to identify pressure transient, chemical analysis or other monitoring techniques to identify location and type of damage. Remedial operations are most effective when the potential cause of production losses can be ranked probabilistically and the depth of the production-reducing event can be estimated as near-field or far-field. Analyzing this data will also assist in defining whether chemical or mechanical treatments such as refracturing or a hybrid treatment system may be the best approach.

Proper fluid and proppant placement are crucial to a successful propped fracture stimulation. Numerous completion diagnostic technologies are available to characterize the placement of the treatment. Until recently, characterization of fracturing fluid cleanup could only be simulated in the laboratory and anecdotally monitored in the field. A technique utilizing a family of unique, environmentally friendly, fracturing fluid compatible, chemical tracers has now been developed for quantifying segment-by-segment recovery for individual fracturing treatments and stage-by-stage recovery for multi-stage fracturing treatments. East Texas Bossier Sand case histories demonstrate that individual, chemically-differentiated and/or proppant-differentiated, fracturing treatment segments are often not being effectively recovered. It has also been demonstrated that the chemical make-up and/or the proppant scheduling of these individual fracturing fluid segments may not only be detrimentally effecting their incremental cleanup but ultimately the production contribution from the corresponding portions of the fractured reservoir. The validation of improvements in fracturing fluid cleanup and production enhancement resulting at least in part from changes in the chemistry of the fracturing fluids and/or changes in proppant scheduling are demonstrated using the tracer technology. Introduction Chemical Frac Tracers In an effort to bolster the level of understanding regarding the dynamics of hydraulic fracture placement and subsequent fluid flowback and cleanup, the technology of chemical frac tracers (CFT's) was born. Borrowing from many years of experience with interwell tracing, several families of non-radioactive chemical compounds were identified that could potentially be placed in segmented portions of the frac fluid so as to more directly measure the flowback efficiency of each fluid segment. Armed with this flowback profile data together with the treatment pressure history of the frac treatment, it was believed that much could potentially be learned both about the dynamics of segmented fluid placement as well as segmented fluid flowback and cleanup. Given the established formation/fracture damage potential for conventional proppant transport fluids, those fluid segments not adequately recovered following the treatment could, in principle, detrimentally affect the effective flow capacity of the fractured interval. Chemical frac tracers were designed to be placed in chemically-differentiated and/or proppant-differentiated fluid segments of the fracturing fluid so as to assess the cleanup of the fracture as a function of segment fluid chemistry and/or fracture geometry. In so doing, it was believed that the sufficiency or insufficiency of addition rates for key frac fluid additives such as polymers, breakers and gel stabilizers could be assessed. It was also believed that the relative cleanup of individual frac treatment stages in a multiple stage completion procedure could be monitored. It was further hoped that inferences could be made from these data regarding lateral placement effectiveness of proppants and vertical communication between zones.

The Cottage Grove formation is an active U.S. mid-continent play where cemented horizontal wells are traditionally stimulated by fracturing several perforation clusters simultaneously using limited entry "perf and plug" or other multi-stage completion solutions. Leaving sections of the lateral unstimulated when fracturing over a large interval can be even more severe in un-cemented completions, where the limited entry technique cannot be relied on to distribute the flow of stimulation fluids in the reservoir. Prior to the introduction of the sequenced fracturing technique, there was no solution to reliably stimulate a large un-cemented or openhole sections. This lead to potential losses of EUR in those wells where for some unplanned event, a section of the wellbore cannot be cemented or isolated with plugs. Recently, a well was drilled and unforeseen issues resulted in 3,300 feet of casing with a completely un-cemented annulus. A remedial cement job was not a feasible option and was quickly dismissed. It was decided to use a new sequenced fracturing technique to complete the stimulation without compromising EUR. This technique uses degradable fibers and multi-sized particles as a composite pill to temporarily plug the fractures and divert stimulation slurry to other regions along the wellbore. In this instance, 20 fracturing stages separated by 12 composite pills and 9 bridge plugs were pumped in sequence to optimize the number of fractures along the wellbore and maximize production.A production and radioactive tracer log run after the operation revealed that the composite pill successfully diverted the treatment fluids from areas previously fractured to previously unstimulated portions of the lateral. As a result, the entire lateral which had been left without cement was ultimately evenly stimulated. This was confirmed by a production log which showed a constant increase in oil and gas production compared to reference wells. Two hundred and six days after the well has been put on production, the well productivity has been more than 30% higher than any offset well.The design, execution and job evaluation of the treatments are detailed in this paper, and highlight the keys to the successful treatment which turned a well initially thought to be a failure into a technical and economic success.

In the Midland Basin, infill wells have high potential of experiencing well-to-well fracture interference or "frac hits". Rock stress alteration around parent wells affect child fracture interactions thus impacting completion effectiveness, well productivity, and well spacing. Endeavor Energy Resources (EER) had a unique opportunity to study parent (hereafter referred to as primary) and child (hereafter referred as infill or active well) interactions and the effects of producing vertical wells on fracture behavior. Two active horizontal wells cross both developed and undeveloped acreage where half of each well is an infill between existing horizontals and the other half is in undeveloped acreage with two existing vertical wells. Operation-driven fracture fluid movement was analyzed by monitoring the treating pressure of the two active wells being completed; and the pressure response of nine shut-in offset horizontals, and ten vertical wells. The measurements and analysis establish a base case to which future fracture- interference monitoring techniques will be compared and later mitigation and intervention. Primary horizontal wells offsetting two infill wells were monitored with wellhead pressure sensors and ESP downhole pressure sensors. Two vertical observation wells (VOW) between the new infill wells were fitted with wellhead wireless pressure sensors and bottomhole pressure gauges. During this area's original development in 2016, vertical wells located hundreds to thousands of feet from the active fraccing well experienced frac interaction. To measure the severity of the invasive fluid movement, wellhead sensors were installed on vertical wells one-half mile, one mile, and one- and-a-half miles away from the active wells. Water and oil tracers were used in the two active infill wells to study fracture fluid movement in conjunction with pressure data. In the unexploited section, the observation horizontal wells’ pressure responses were examined for fracture shadowing (inter-well poro-elastic response) stress shadowing (intra-well dynamic active fracture interactions (DAFI) (Daneshy, 2018), and fracture-to-fracture connections both temporary and long term. As fracture operations approached a primary vertical well (depleted zones), frac fluid was distributed vertically among multiple horizons through perforations in the existing well and laterally into horizontal primary wells. The three laterally closest primary wells, completed in three different intervals, had similar strong pressure responses to a common active stage suggesting a geologic cause. As for the vertical observation wells, fluid incursion was observed over 8400 feet away. The vertical wells between the two horizontal active infills had a 200 ft. to 400 ft. radius of pressure disturbance as the frac stages approached their locations. Fracture stages within the 200 ft. to 400 ft. radius caused direct hits while stages outside this radius caused mild pressure increases identified as fracture shadows. Legacy fields in Midland Basin are usually Held by Production (HBP). Consequently, horizontal development may be around existing vertical wells. Redevelopment of acreage into unexploited benches after primary benches have been horizontally developed is another situation many companies face. By sharing this case study, the authors want other operators who are facing these common issues to leverage these learnings. The significance of ignoring potential fracture interference and hydraulic connection may result in ineffective fractures, reduced stimulated reservoir volume (SRV), or wells sharing SRV. Ultimately this means reduced resource recovery which may occur in either or both the primary and infill wells.

Millions of dollars in production losses are occurring from fracture-driven well-to-well interference (frac hits) in horizontal wells in unconventional play reservoirs. The work presented in SPE 187192 has been continued in this paper with a new case study (Case Study V), data from a pair of Wolfcamp B wells in the Permian Basin. The parent well suffered fracture interference during the child well's stimulation operations, negatively effecting production. The child and parent wells were both completed with the "plug and perf" technique. The parent well was completed with 74 stages while the child well's completion consisted of 105 frac stages. The child well was drilled with a longer lateral and the first 72 stages of the well's fracturing operations caused clear, repeatable pressure changes in the parent well. The data from these two wells is rich in cause and effect and permits compelling observations and conclusions. These findings were then compared to those from Case Studies I-IV, SPE 187192. Detailed plots of the pressure changes superimposed with fracturing data were created and studied to better understand the significance and cause of what was happening to the Case Study V parent well. The shut-in pressure data from the parent well was taken at the intake of the electrical submersible pump (ESP) and recorded in 1-3 minute increments. Both wells have the same number of perf clusters per stage, stage spacing and amount of sand per stage. One-second fracture stimulation data for both completions was available. Case Study V plots and examples from Case Studies I-IV were put side-to-side and back-to-back to quickly view the similarities and differences. Fact-based conclusions were reached regarding causality of fracture-driven communication and interference between these wells. Preface The study for this paper is based on and uses data from nearly 200 individual fracture stimulation stages pumped in five pairs of wells. In order to document and discuss that much information, there are numerous plots and illustrations. While this is perhaps unconventional, it must be pointed out that a paper that is focused on data MUST show the data. Time constraints prevented the inclusion of several additional plots and "Part III" is being planned and is in the works. SPE 187192 (part I), King et al (2017) will be referred to several times and a few of the old plots are shown. There are new plots and observations from Case Studies I-IV.