Abstract The Pawnee M5.8 earthquake is the largest event in Oklahoma instrument recorded history. It occurred near the edge of active seismic zones, similar to other M5+ earthquakes since 2011. It ruptured a previously unmapped fault and triggered aftershocks along a complex conjugate fault system. With a high-resolution earthquake catalog, we observe propagating foreshocks leading to the mainshock within 0.5 km distance, suggesting existence of precursory aseismic slip. At approximately 100 days before the mainshock, two M ≥ 3.5 earthquakes occurred along a mapped fault that is conjugate to the mainshock fault. At about 40 days before, two earthquakes clusters started, with one M3 earthquake occurred two days before the mainshock. The three M ≥ 3 foreshocks all produced positive Coulomb stress at the mainshock hypocenter. These foreshock activities within the conjugate fault system are near-instantaneously responding to variations in injection rates at 95% confidence. The short time delay between injection and seismicity differs from both the hypothetical expected time scale of diffusion process and the long time delay observed in this region prior to 2016, suggesting a possible role of elastic stress transfer and critical stress state of the fault. Our results suggest that the Pawnee earthquake is a result of interplay among injection, tectonic faults, and foreshocks.
Abstract Sealed Wellbore Pressure Monitoring (SWPM) has been utilized across North and South America Basins with over 16,000 stages monitored as of June 2022. Since May 2020, the analysis procedure has been automated using a cloud-based software platform designed to ingest, process, and analyze high-frequency hydraulic fracturing data (Iriarte et al., 2021). A real time option of SWPM was also developed to aid in real time fracturing decisions (Ramirez et al., 2022). The latest development is the added capability of a fracture model that can automatically history match the volume to first responses (VFRs) determined from SWPM. This next level allows for the matching of the VFRs and the visualization of the resulting fracture geometries from a fully-coupled fracture propagation, reservoir, and geomechanics simulator. The simulator is capable of accounting for complex processes such as poroelastic stress changes from depletion, allowing for evaluation of complex interactions of fracture propagation and depletion. Insights gained from this process allows the operator to optimize their completion design faster and with fewer field trials. This paper’s focus is a case study of the DOE Eagle Ford refracturing project where a range of completion designs were trialed while monitoring offset SWPM and fiber optic strain. The resulting VFRs of the SWPM project were compared to the fiber data and then used to calibrate the fracture model. Fracture model calibration was first performed assuming that restimulation fractures propagated independently of the previously created fractures. The VFR of each stage design was calculated and summarized. The model is constructed with three stage designs primarily identified by cluster count: 7-clusters, 12-clusters, and 22-clusters. The VFR for the 7-cluster stage design was then used as an objective in an automated history matching algorithm employing the fracture model. The resulting best fit model was then evaluated on VFRs for the 12 and 22-cluster stage designs. The results demonstrate the model calibrated to the VFR of the 7-cluster stage design was able to predict VFRs in the far field for 12 and 22-cluster stage designs. Further, it is shown that including the original fractures in the model and allowing crossflow between the original and newly created fractures can match the rapid VFRs observed on a minority of stages. These same results were confirmed by the fiber data (not shared with modelers prior to calibration). Conclusions of the DOE project will show the optimum cluster spacing, cluster count and stage spacing as confirmed by the SWPM analysis and the fracture modeling.
Abstract The downhole monitoring of strain using Fiber Optics (FO) can reveal unique information about the propagation and geometry of hydraulic fractures between nearby wells during stimulation and production. This work aims at creating a catalogue of commonly observed strain-rate signals captured in a not yet stimulated nearby observation well equipped with either a permanently or temporarily installed FO cable. This catalogue is the result of an informal collaboration between experience FO users from academia, service providers, consulting companies, and operators. In the creation of this first edition of a strain-rate catalogue, we considered two main types of stimulation categories (single and multi-entry) as well as the angle between the hydraulic fractures and the segment of the well where the strain-rate signals are observed (horizontal vs. vertical segments). In the catalogue we show a series of representative examples of two main types of far-field strain Fracture Driven Interactions (s-FDI) commonly encountered in frac diagnostics: 1. Vertical hydraulic fractures being monitored in a lateral portion of a horizontal well and 2. Vertical fractures being monitored in a vertical observation well. The catalogue is organized around commonly observed s-FDI motifs. Because interpretation of observed strain-rate signals can be subjective, when possible, we included observed examples with a brief description of our interpretation, as well as synthetic signals from geomechanical models of similar motifs. The strain-rate motifs were modeled based on first physical principles for rock deformation. These models serve to support the proposed interpretation of the observed signals. FO strain rate monitoring is changing our understanding about the hydraulics fracturing process. The information from FO strain is not available by other commonly used fracture diagnostic techniques. Strain- rate fractures driven interactions between wells occur in predictable patterns (Frac Domain and Stage Domain Corridors – FDC & SDC respectively) which are typically in line with the cluster spacing and stage length in the borehole being stimulated. Using FO strain monitoring, we now know that hydraulic fractures are larger than first anticipated, both in length and height. Many examples indicated that there is a direct correspondence between the near-field and far-field stimulation geometries. The lack of isolation due to cement quality and or plug failure manifests in the far-field geometries observed via FO strain-rate in nearby wells. The use of FO strain monitoring has also revealed that reopening of hydraulic fractures is common not only between prior and infill wells but also between wells from the same stimulation vintage. All these observations and conditions must be considered when interpreting new strain-rate datasets and more importantly when designing new hydraulic fracturing operations and considering different stimulation order (zipper schedule), as well as when making decisions about the vertical and lateral spacing of adjacent wells. The purpose of this industry-first edition strain-rate catalogue is to aid, new and experienced FO users, on the interpretation of strain-rate datasets. Ultimately, the accurate interpretation of FO strain data will not only help calibrate geomechanical and reservoir models but also directly influence where and how we complete unconventional wells. Nowadays, many s-FDI examples exist in scattered publications with formats that aren’t easily comparable for new users of the technology. In this project, we expand upon those publications to create an encompassing analysis with up-to-date interpretations where we have formalized the formatting of figures for better readability (color scheme, scales, etc.). What has resulted from this collaborative effort is a novel catalogue not available before in the FO published literature.
Abstract Until recently, microseismic has been the primary diagnostic for estimating "bulk" or stage-level fracture geometry, including asymmetry due to parent-child interactions, for modern multi-cluster plug-and-perf completions. However, microseismic cannot provide details on individual fractures or cluster-level measurements. With the continued advances in fiber optic technologies, we can now measure cluster level fracture behavior at the wellbore and in the far-field. Characterizing the relationship between wellbore and far-field fracture geometry, referred to as fracture morphology, is important when simultaneously optimizing completion design and well spacing. Microseismic and fiber optics are very robust, but expensive, technologies and this limits the frequency of their application. Recently developed low-cost pressure-based technologies enable high-volume data acquisition but may not provide the same level of detail compared to microseismic and fiber optic measurements. This paper presents a case history that details the application of deployable fiber optics to characterize fracture geometry and morphology using microseismic and strain data. The paper also presents results from Sealed Wellbore Pressure Monitoring (SWPM) (Haustveit et al. 2020), comparing the lower-cost SWPM technology to the higher-cost deployable fiber. Wireline-fiber was deployed in the inner two wells, one Middle Bakken (MB) and one Three Forks (TF), of a four-well pad. Surface pressures were recorded on all wells on the pad and nearby parent wells. The outer two wells, one MB and one TF, were completed first, using zipper operations. Fiber-based microseismic and strain measurements were used to characterize fracture geometry and morphology, and parent-child interactions. Pressure measurements on the two inner wells were used for SWPM, providing estimates of completion effectiveness and fracture geometry using Volume to First Response (VFR) measurements. The microseismic data showed asymmetric growth from the eastern well to the parent well pad, with fractures covering the entire parent well pad. More symmetric fracture growth was measured for the western well, as the parent well pad was farther away. The microseismic data provided fracture geometry measurements consistent with previous measurements in the same area using a geophone array. The SWPM results compared favorably to the fiber measurements using the high confidence data. However, there were data acquisition complexities with both technologies that will be detailed in the paper. Fiber strain measurements provided detailed information on fracture morphology, showing significant decreases in the number of far-field hydraulics as distance increases from the completion well. The advancements in Low Frequency Distributed Acoustic Sensing (Ugueto et al. 2019) provides the ability to monitor hydraulic fractures approaching, passing above/under, and intersecting the monitoring location. Both fiber and SWPM showed much faster fracture growth within the same formation compared to fracture growth between formations. The integration of the fiber optic measurements and SWPM results have provided important insights into fracture geometry and morphology, leading to improved hydraulic fracture models.
Abstract This case study details the use of Sealed Wellbore Pressure Monitoring (SWPM) to improve the characterization of fracture geometry and propagation during stimulation of inter-connected stacked pay in the South Texas Eagle Ford Shale. The SWPM workflow utilizes surface pressure gauges to detect hydraulically induced fracture arrivals athorizontal monitor locations adjacent to the stimulated wellbore (Haustveit et al. 2020). A stacked and staggered development in Dewitt County provided the opportunity to jointly evaluateprimary completion and recompletion efforts spanning three reservoir target intervals. Fivemonitor wells at varying distances across the unit were employed for SWPM during the stimulation of four wells. An operational overview, analysis of techniques, correlation with seismic attributes, image log interpretations, and fracture model calibration are provided. Outputs from this workflow allow for a refined analysis ofthe overall completion strategy. The high-density, five well monitor array recorded a total of 160 fracture arrivals at varying vertical and lateral distances, with far-field fracture arrivalsprovidingsignificant insight into propagation rates and geometry. Apronounced trend occurred in both arrival frequency and volumes pumped as monitor locations increased in distance from the treatment well. Specific to target zone isolation, it was identified that traversing vertically in section through a high stress interval yielded a 30% reduction inarrival frequency. An indirect relationship between horizontal distance and arrival frequency was also observed when monitoring from the same interval. A decrease in fracture arrivals from 70% down to 8% was realized as offset distance increased from 120 to 1,700 ft. The results from this study have proven to be instrumental in guiding interdisciplinary discussion. Assessing fracture geometry and propagation during stimulation, particularly in the co-development of a stacked pay reservoir, is paramount to the determination of proper completion volume, perforation design, and well spacing. Leveraging the observations of SWPM ultimately provides greater confidence in field development strategy and economic optimization.
Abstract Many previous studies have suggested that wastewater disposal is the most probable factor affecting increased seismicity in Oklahoma since 2009. While this relationship is clear at the state scale, a systematic quantitative analysis of the spatiotemporal relationships between injection and seismicity is needed. We first apply multiscale analyses to assess the temporal correlation between injection rate and seismicity rate at a range of different grid sizes, which demonstrate clear temporal correlations within the two main seismic regions at variable time delays. The time delay variability decreases with larger grid sizes, whereby the average time delay ranges from 150 to 220 days. The average time delay at large scales is consistent with inferred large‐scale diffusive migration away from areas of high injection rates with diffusivities of 0.5 to 2.0 m 2 /s. The inferred large‐scale diffusivities are consistent with an expected range of diffusivity within the Arbuckle Group where wastewater disposals are occurring. However, individual earthquake clusters have diffusivities that are about one to two orders lower than the large‐scale models. We interpret this as a manifestation of a two‐layered diffusion model with high diffusivity within the injection layer above basement, which facilitates stress transfer at a larger spatial footprint, triggering seismic slip at multiple seismogenic faults within the crystalline basement with low diffusivity, similar to fluid‐driven clusters in other tectonic regions.
Abstract A novel diagnostic processing technique called Conductive Fracture Imaging (CFI) measures hydraulic and conductive fractures using microseismic events as a source. The method was applied to three datasets located in onshore unconventional formations in the United States. CFI results were in all cases first delivered independent of any external diagnostic data and only subsequently compared to multiple diagnostics such as microseismic, fiber cross-well strain (CWS), 3D seismic, and recovered core under supervision of Devon Energy’s Subsurface Team. The comparison reveals a reasonable agreement of the CFI results with cross-well strain for both height and transverse conductive fracture growth. CFI was able to image fractures out 1 mile from the observation lateral, with fractures imaged in areas of no microseismic activity. Furthermore, CFI successfully quantified the height growth of fractures aligned with the pre-existing faults and how natural structures influence conductivity fracture distribution. CFI reveals a valid relationship with cored & interpreted conductive, hydraulic, and natural fractures. The method provides dynamic images showing fracture morphology from the near-wellbore into the far-field reservoir. Complimentary analytics of relationships between CFI and reservoir properties, limited entry perforation designs, stress shadowing, and depletion effects may generate significant new observations and key learnings to industry as this technique is more broadly adopted.
Fluid injection operations and the connected increase in pore pressure can have undesirable side effects such as induced seismic activity, fault slip and wellbore damage. Here, we present two statistical methods that allow for an identification of fault activation and induced seismic activity. First, we differentiate induced from tectonic seismicity based on a significant increase in background seismicity rates. We determine temporal variations in background rates by fitting earthquake interevent-times with a two-parametric gamma distribution. The corresponding parameters provide insight into short-period aftershock clustering and longer period background seismicity rate changes. We show that temporal changes in background rates can be used to identify regions with induced seismicity in the central United. Second, we identify fault activation processes by analyzing temporal variations in Gutenberg-Richter b-value A significant drop in b-value can potentially be indicative of fault activation during continuous injection operations. Adjusting injection operations in response to jumps in background rates and decreasing b-values may help control fault activation and induced earthquake activity. Presentation Date: Wednesday, October 19, 2016 Start Time: 8:00:00 AM Location: Lobby D/C Presentation Type: POSTER
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