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Abstract A straightforward test with debatable analysis methods, the diagnostic fracture injection test (DFIT) is a pressure-transient test extensively used for reservoir and geomechanical characterization of tight/shale formations. The test provides some key data and information to reservoir and well completion engineers including instantaneous shut-in pressure (ISIP), pore pressure, closure stress, fluid efficiency, reservoir flow capacity, and fracture leak-off regime. A comprehensive regional or field-wide study of the DFITs is deemed very useful for operators at any stage of exploration and development. In this study, DFITs from a group of 174 Montney and Duvernay wells operated by more than 30 producing companies are quality checked and analyzed consistently. The results from DFITs are then compared against the standard poroelasticity equation. The data set of the current study covers a wide range of DFIT conditions and reservoir and geomechanical properties which helps the authors develop reliable correlations for reservoir characterization purposes. True vertical depth (TVD) of the wells ranges from less than 1000m to more than 4000m leading to a wide range of pressure and stress conditions. The study also covers all the geographical areas of Montney and Duvernay. The results ofthe DFITs are used to develop usefulcross-plot betweenpore pressure and closure pressure.A relationship between closure pressure from compliance method and G-function analysis method for Montney and Duvernay is also provided. Results of example DFITs from depleted areas were also provided which gives an idea about the depletion level and the associated well performance degradation. The current study gives field-wide understanding of the variations and distributions of reservoir and geomechanical properties in Montney and Duvernay based on DFIT analysis of a sizable population of wells.
Abstract Understanding effective fracture length and characterizing drainage patterns is critical for optimal development of unconventional resources. This paper documents a comprehensive field experiment in the Bakken formation, where several fracture diagnostic technologies and drainage mapping methods were used in a unique project setup to measure effective fracture length and map drainage. Two vertical wells (V1 and V2) were drilled 1,000 ft away from a Bakken lateral (H1) with 10 years of production (Fig. 1). The two vertical wells were 200 ft apart. V2 was used for microseismic and deformation (downhole tilt) measurements, while V1 was used for pressure measurements and hydraulic fracture characterization. The project consisted of re-pressurizing the existing lateral (parent well), using microseismic monitoring to map drainage (designated MDD, Dohmen et al. 2013, 2014, 2017). A DFIT was performed in the V1 well before the MDD to measure local stress and pore pressure. Following the MDD, a small propped fracture treatment was pumped in the V1. The H1 well was then produced for 4 months and DFITs pumped in the V1 and V2 wells. This comprehensive fracture diagnostic dataset was integrated with detailed core and log measurements, hydraulic fracture modeling, and advanced reservoir simulation to characterize the hydraulic fracture performance. The H1 MDD indicated that the major pressure depletion (drainage) was approximately 500 ft on either side of the lateral. H1 BHP showed local reservoir pressure was 1,000 psi. The initial V1 DFIT showed virgin reservoir pressure, but surprisingly, the 20 bbl DFIT injection was detected on the H1 BHP gauge. Microseismic mapping of the V1 fracture treatment (15 klbs, 600 bbl) showed a planar fracture with a half-length of 1,000 ft. The V1 fracture "hit" the H1, measured by microseismic and confirmed by a 1,650 psi increase in H1 BHP. The microseismic showed a symmetrical fracture, suggesting that the H1 re-pressurization mitigated the detrimental effects of parent well depletion that can cause severe asymmetry. Downhole tilt and microseismic showed fracture height quickly extended downward through the lower Bakken shale into the Three Forks. The V1 was not produced. However, the H1 oil rate doubled after the V1 frac hit, indicating significant stimulation. V1 DFIT #2 showed 1,800 psi depletion, while the V2 DFIT showed approximately 1,000 psi depletion, confirming that the V1 fracture is "flowing" into the H1 lateral 1,000 ft away. The reservoir simulation history match indicated low fracture conductivity, but enough to improve well productivity and drain oil over 1,000-ft from the H1 lateral. This paper details a comprehensive fracture diagnostic dataset gathered in a unique field laboratory where a single hydraulic fracture from a vertical well is used to characterize fracture conductivity and flowing length.
We use a high-quality dataset in the Bakken Shale to calibrate a numerical model to a complex and diverse set of parent/child observations. Two vertical wells (V1 and V2) were drilled 1000 ft and 1200 ft away from a legacy well with 10 years of production, H1. A DFIT was performed in the V1, followed by a 24 hour low-rate injection in the H1 (a microseismic depletion delineation, MDD, test). Subsequently, a small frac job was performed in the V1, followed by DFITs in the V1 and V2. The dataset yields a diversity of data to calibrate a numerical model: historical production of the H1, pressure response in the H1 from the MDD injection and the V1 fracture treatment, production rate uplift in the H1 following the V1 frac, microseismic, and pressure response during the three DFITs. The entire dataset was history matched in a single continuous simulation with a numerical simulator that fully integrates hydraulic fracture and reservoir simulation. The simulation was set up to closely match a geologic model that was built in prior work. The integrated simulation allows simulation of the fractures reopening around the H1 as a consequence of the MDD, the transport of proppant from the V1 to the H1 well, and the subsequent communication and poroelastic stress response. The Biot coefficient was calibrated to match the observed change in stress at the H1 well after ten years of depletion. The fracture toughness was calibrated to match the observed fracture geometry from the microseismic around the V1 well during fracturing. A proppant transport parameter called ‘maximum immobilized proppant’ was tuned to the production and DFIT data. The match to the V2 DFIT suggests that it is not directly in contact with the V1 fracture, even though the wells are relatively close together along fracture strike. The initial V1 DFIT suggests that it has, at most, weak contact with the H1. The second V1 DFIT, performed after the fracturing treatment, demonstrates communication with the H1, and consequently, depletion. The observations demonstrate that the H1 was able to produce from the previously undepleted rock around the V1, even though it was 1000 ft away. Overall, the results indicate that Bakken wells can achieve substantial (at least 1000 ft) effective half-length, that frac hits on parent wells in the Bakken do not necessarily result in production degradation and can even increase production, that the apparent Biot coefficient is relatively low (∼0.34), that the amount of proppant trapping due to localized screenout is relatively low (but nonzero), and this entire, complex dataset can be explained using a planar fracture modeling approach.
Abstract Stacked pay in unconventional plays has emerged as the primary focus for a majority of operators in North America. The number of completion targets range from two zones in the Bakken to more than ten zones in areas of the Permian Basin. Proper development of multi-zone reservoirs will yield the greatest recovery factor for the unit and minimize the drilling hazards and completion challenges related to depletion. Proper development maximizes the propped height while minimizing propped fracture overlap; this combination improves recovery without overcapitalizing the completion. This paper will review existing and emerging diagnostic tools deployed in the STACK (Sooner Trend Anadarko Canadian and Kingfisher counties) to identify the number of landing intervals required to effectively drain the Meramec formation. The Meramec formation has produced a number of prolific wells from several benches contained within several hundred feet of reservoir. The diagnostic tools that will be reviewed in this paper include electromagnetic (EM) proppant detection, radioactive (RA) proppant tracer surveys and offset pressure responses. The EM proppant and RA proppant surveys were used in a vertical well to measure the propped fracture height. The presence of the RA tracer is detected using a spectral gamma ray log; the EM proppant is mapped using a surface array of electric- and magnetic-field receivers. Downhole gauges in a vertical well measured the pressure responses generated during the treatment of an offsetting horizontal well to evaluate the effects of fluid viscosity on fracture height. Results from the diagnostic tools have been integrated into the well spacing strategy for upcoming development units.
Tran, Tony (Discovery Natural Resources) | Miller, Ryan (Discovery Natural Resources) | Pottebaum, Brad (Discovery Natural Resources) | McDowell, Bryan (Discovery Natural Resources) | Yoelin, Alan (Discovery Natural Resources) | Steinke, Lee (Discovery Natural Resources)
Abstract As operators transition from field delineation to field development in unconventional reservoirs, well spacing and stimulation designs become critical for maximizing an asset's net present value (NPV). Unfortunately, these variables can be interdependent, and changing one variable frequently changes the other. This interplay becomes extremely complex and often leads larger operators to reduce uncertainty through modeling. Historically, smaller operators have been limited in modeling efforts due to budget and staff constraints, but recent software and hardware advances have significantly reduced the time and cost of such work. A practical reservoir simulation workflow for small teams developing unconventional reservoirs is demonstrated here. The workflow consists of two primary processes: (1) history matching historical wells and (2) developing stimulation designs for future wells. Historical wells are history matched to validate the static geologic model, hydraulic fracture models, and dynamic reservoir models before the models are utilized for future stimulation designs. Once validated, the various inputs may be used to (a) design well stimulation designs and (b) predict expected production. The process is highly iterative and must be cross-checked against external data when available. To demonstrate the workflow, a case study in the Wolfcamp Formation is presented here. The case study includes seven parent wells, three of which were used for history matching, and eleven child wells whose stimulation designs were greatly influenced by the workflow. Introduction Geologic Background The Midland sub-basin (Figure 1) is a northwest-trending foreland sedimentary basin whose boundaries are defined by the Eastern Shelf (east), Central Basin Platform (west), and Marathon-Ouachita orogenic belt (south). It is part of the larger Permian basin, which also includes the western-most Delaware sub-basin straddling western Texas and southeastern New Mexico. The basin contains Cambrian- to Cretaceous-aged sedimentary rocks and hosts hydrocarbon-bearing rocks throughout most of the Paleozoic section. The Permian-aged Wolfcamp Formation is one of the largest source rocks in the basin and is the focus of active unconventional reservoir development. The unit was deposited during a period of rapid changes in depositional environment that resulted in a complex stratigraphic architecture composed of organic-rich shales, mudstones, and detrital carbonates. This vertical and areal variability creates a development area with a wide range of target intervals, each with their own petrophysical and geomechanical properties.