Characteristics of Acoustic Emission Waveforms Induced by Hydraulic Fracturing of Coal under True Triaxial Stress in a Laboratory-Scale Experiment

Hydraulic fracturing (HF) is an effective technology to prevent and control coal dynamic disaster. The process of coal hydraulic fracturing (HF) induces a large number of microseismic/acoustic emission (MS/AE) waveforms. Understanding the characteristic of AE waveforms’ parameters is essential for evaluating the fracturing effect and optimizing the HF strategy in coal formation. In this study, laboratory hydraulic fracturing under true triaxial stress was performed on a cubic coal sample combined with AE monitoring. The injection pressure curve and temporal variation of AE waveforms’ parameters in different stages were analyzed in detail. The experimental results show that the characteristics of the AE waveforms’ parameters well reflect the HF growth behavior in coal. The majority of AE waveforms’ dominant frequency is distributed between 145 and 160 kHz during HF. The sharp decrease of the injection pressure curve and the sharp increase of the AE waveforms’ amplitude show that the fracture already runs through the coal sample during the initial fracture stage. The “trapezoidal” rise pattern of cumulative energy and most AE waveforms with low amplitude may indicate the stage of liquid storage space expansion. The largest proportion of AE waveforms’ energy and higher overall level of AE waveforms’ amplitude occur during the secondary fracture stage, which indicates the most severe degree of coal fracture and complex activity of internal fracture. The phenomenon shows the difference in fracture mechanism between the initial and secondary fracture stage. We propose a window-number index of AE waveforms for better response to hydraulic fracture, which can improve the accuracy of the HF process division.

Microbial colonization and persistence in deep fractured shales is guided by metabolic exchanges and viral predation

Background Microbial colonization of subsurface shales following hydraulic fracturing offers the opportunity to study coupled biotic and abiotic factors that impact microbial persistence in engineered deep subsurface ecosystems. Shale formations underly much of the continental USA and display geographically distinct gradients in temperature and salinity. Complementing studies performed in eastern USA shales that contain brine-like fluids, here we coupled metagenomic and metabolomic approaches to develop the first genome-level insights into ecosystem colonization and microbial community interactions in a lower-salinity, but high-temperature western USA shale formation. Results We collected materials used during the hydraulic fracturing process (i.e., chemicals, drill muds) paired with temporal sampling of water produced from three different hydraulically fractured wells in the STACK (Sooner Trend Anadarko Basin, Canadian and Kingfisher) shale play in OK, USA. Relative to other shale formations, our metagenomic and metabolomic analyses revealed an expanded taxonomic and metabolic diversity of microorganisms that colonize and persist in fractured shales. Importantly, temporal sampling across all three hydraulic fracturing wells traced the degradation of complex polymers from the hydraulic fracturing process to the production and consumption of organic acids that support sulfate- and thiosulfate-reducing bacteria. Furthermore, we identified 5587 viral genomes and linked many of these to the dominant, colonizing microorganisms, demonstrating the key role that viral predation plays in community dynamics within this closed, engineered system. Lastly, top-side audit sampling of different source materials enabled genome-resolved source tracking, revealing the likely sources of many key colonizing and persisting taxa in these ecosystems. Conclusions These findings highlight the importance of resource utilization and resistance to viral predation as key traits that enable specific microbial taxa to persist across fractured shale ecosystems. We also demonstrate the importance of materials used in the hydraulic fracturing process as both a source of persisting shale microorganisms and organic substrates that likely aid in sustaining the microbial community. Moreover, we showed that different physicochemical conditions (i.e., salinity, temperature) can influence the composition and functional potential of persisting microbial communities in shale ecosystems. Together, these results expand our knowledge of microbial life in deep subsurface shales and have important ramifications for management and treatment of microbial biomass in hydraulically fractured wells.

Coupling Relationship between Lithofacies and Brittleness of the Shale Oil Reservoir: A Case Study of the Shahejie Formation in the Raoyang Sag

Analyzing the characteristics of rock brittleness in low-permeability mudstone and shale (MS) formations is imperative for efficient hydraulic fracturing stimulation. Rock brittleness depends on the mineral composition, organic matter abundance, and bedding structure. Based on the MS from Shahejie Formation mineral composition (clay mineral, felsic mineral, and calcareous mineral contents), total organic content, and bedding structure (laminated, laminar, and massive), six types of lithofacies were identified: clay-rich MS, felsic-rich MS, calcareous-rich MS, clay MS, felsic MS, and calcareous MS. The quartz, feldspar, calcite, and dolomite of the Shahejie Formation are brittle minerals. Consequently, lithofacies with high felsic and calcareous mineral contents are more brittle. In addition, laminated and laminar MS are also conducive to hydraulic fracturing. Therefore, laminated, organic-rich, and calcareous-rich MS are the dominant lithofacies for hydraulic fracturing in the Shahejie Formation. The lithofacies and brittleness index were predicted by the response characteristics between mineral compositions and logging curves. The 3521–3552 m section of well B11x is dominated by calcareous-rich MS with developed laminae, representing a favorable section for hydraulic fracturing. Fragile minerals and oil are widely developed in the lower part of the lower 1st member of the Shahejie Formation (Es1L) in the southwestern part of Zhaohuangzhuang-Suning, where hydraulic fracturing can be used to increase shale oil production.

Controlled Frac Height Growth Technique to Avoid Contacting Water-Bearing Layer

Many techniques have been used to model, diagnose and detect fracture dimension and propagation during hydraulic fracturing. Diagnosing fracture dimension growth vs time is of paramount importance to reach the desired geometry to maximize hydrocarbon production potential and prevent contacting undesired fluid zones. The study presented here describes a technique implemented to control vertical fracture growth in a tight sandstone formation being stimulated near a water zone. This gas well was completed vertically as openhole with Multi- Stage Fracturing (MSF). Pre-Fracturing diagnostic tests in combination with high-resolution temperature logs provided evidence of vertical fracture height growth downward toward water zone. Pre-fracturing flowback indicated water presence that was confirmed by lab test. Several actions were taken to mitigate fracture vertical growth during the placement of main treatment. An artificial barrier with proppant was placed in the lower zone of the reservoir before main fracturing execution. The rate and viscosity of fracturing fluids were also adjusted to control the net pressure aiming to enhance fracture length into the reservoir. The redesigned proppant fracturing job was placed into the formation as planned. Production results showed the effectiveness of the artificial lower barrier placed to prevent fracture vertical growth down into the water zone. Noise log consists of Sonic Noise Log (SNL) and High Precision Temperature (HPT) was performed. The log analysis indicated that two major fractures were initiated away from water-bearing zone with minimum water production. Additionally, in- situ minimum stress profile indicated no enough contrast between layers to help confine fracture into the targeted reservoir. Commercial gas production was achieved after applying this stimulation technique while keeping water production rate controlled within the desired range. The approach described in this paper to optimize gas production in tight formation with nearby water contact during hydraulic fracturing treatments has been applied with a significant improvement in well production. This will serve as reference for future intervention under same challenging completion conditions.

Fracturing Technology - Can We Finally Control Fracture Height?

For as long as we have been performing hydraulic fracturing, we have been trying to ensure that we stay out of undesirable horizons, potentially containing water and/or gas. The holy grail of hydraulic fracturing, an absolute control of created fracture height, has eluded the industry for more than 70 years. Of course, there have been many that have claimed solutions, but all the marketed approaches have at best merely created a delay to the inevitable growth and at worst been a snake-oil approach with little actual merit. Fundamentally, the applied techniques have attempted to delay or influence the underlying equations of net-pressure and stress variation; but having to ultimately honour them and by doing so then condemned themselves to limited success or outright failure. Fast forward to 2020, and a reassessment of the relative importance of height-growth constraint and what may have changed to help us achieve this. The development of unconventionals are focused on creating as much surface area as possible in micro/nano-Darcy environments, across almost any phase, but with typically poor line of sight to profit. However, the more valuable business of conventional oil and gas is working in thinner and thinner reservoirs with an often-deteriorating permeability, but with a significantly higher potential economic return. What unconventional has successfully delivered however, is a rapid deployment and acceleration in a range of completion technologies that were unavailable just a few years ago. We will demonstrate that these technologies potentially offer the capability of finally being able to control fracture height-growth. Consideration of a range of previously applied height-growth approaches will demonstrate how they attempted to fool or fudge height growth creation mechanisms. With this clarity, we can consider what advances in completion technology may offer in terms of delivering height growth control. We suggest that with the technology and approaches that are currently available today, that height-growth control is finally within reach. We will go on to describe a multi-well Pilot program, in deployment and execution in 2020/021 in Western Siberia; where billions of barrels remain to be recovered in thin oil-rim, low permeability sandstone reservoirs below gas or above water. A comprehensive assessment of the myriad of height-growth approaches that have been utilized over the last 70 years was performed, but in each case demonstrated the fallibility and limitations of each of these. However, rather than the interpretation that such control is not achievable, instead we will show a mathematically sound approach, along with field data and evidence that this is possible. The presentation will demonstrate that completion advances over the last 10 - 15 years make this approach a reality in the present day; and that broader field implementation is finally within reach.