Geomechanical modeling of microseismic depletion delineation

Proceedings of the 6th Unconventional Resources Technology Conference

Motiee

Kechemir

2018

The URTeC Technical Program Committee accepted this presentation on the basis of information contained in an abstract submitted by the author(s). The contents of this paper have not been reviewed by URTeC and URTeC does not warrant the accuracy, reliability, or timeliness of any information herein. All information is the responsibility of, and, is subject to corrections by the author(s). Any person or entity that relies on any information obtained from this paper does so at their own risk. The information herein does not necessarily reflect any position of URTeC. Any reproduction, distribution, or storage of any part of this paper by anyone other than the author without the written consent of URTeC is prohibited.

Section: Geomechanical Modeling and H2 And H4 Hydraulic Fracture Modementioning

confidence: 99%

Integrating Microseismic, Geomechanics, Hydraulic Fracture Modeling, and Reservoir Simulation to Characterize Parent Well Depletion and Infill Well Performance in the Bakken

Proceedings of the 6th Unconventional Resources Technology Conference

Motiee

Kechemir

2018

Multidisciplinary Data Gathering to Characterize Hydraulic Fracture Performance and Evaluate Well Spacing in the Bakken

Lorwongngam

Day 1 Tue, February 05, 2019

Gradl

et al. 2019

To effectively drain hydrocarbon from unconventional plays, operators have been optimizing their drilling spacing unit (DSU) well spacing for many years. This paper presents a continuous improvement of Bakken well spacing using trial pads with smaller spacing and multidisciplinary data gathering to understand the most effective spacing between wells. The operator's standard well spacing between Middle Bakken (MB) wells in the East Nesson (EN) area [Alger Field] ranges from 500 to 700 ft. To understand the optimum spacing between wells in this area, the operator trialed well spacing of 500 ft between like formations. The spacing between Middle Bakken and Three Forks wells was 250 ft. Data gathered during the spacing trial included microseismic, microseismic depletion delineation (MDD), radioactive (RA) tracers, chemical tracers, image logs, pressure measurements during completion/flowback/early-time production, and diagnostic fracture injection tests (DFITs). The data was used to calibrate advanced hydraulic fracture models and guide next-generation reservoir simulation history matching to characterize multiwell production behavior. The MDD in the parent well provided data to "map" drainage patterns, showing that drainage was limited to the MB formation. However, microseismic showed that hydraulic fracture height extended from the Three Forks second bench (TF2) up through the Three Forks first bench (TF1), Middle Bakken, and into the overlying Lodgepole (LP)—connecting the entire Bakken petroleum system. The microseismic also showed asymmetric fracture growth toward the parent well in the DSU, but the asymmetry diminished as completions progressed away from the parent well. In addition to the MB-TF connectivity indicated from the microseismic, RA tracers pumped from a TF2 well were detected in a Middle Bakken well. The implied transport of proppant from a lower TF completion to the MB increases the likelihood of production communication between formations. Chemical tracers (oil and water) pumped during hydraulic fracturing operations were found from one end of the pad to another (over 2,500 ft) regardless of formation; another confirmation of hydraulic communication between Middle Bakken and Three Forks wells. The hydraulic fracture model was calibrated using microseismic data and used for subsequent reservoir simulation history matching. The workflow consisted of modeling the parent well hydraulic fractures and history matching production, performing geomechanical modeling to determine the effects of parent well depletion on 3D stress state for hydraulic fracture modeling of the infill wells, and production history matching of the entire pad. The modeling showed significant fracture-to-fracture communication and well-to-well interference. The operator quickly used these learnings to optimize well spacing across the area to maximize DSU value.

Case History of Drainage Mapping and Effective Fracture Length in the Bakken

Day 1 Tue, February 04, 2020

Litvak

Prasad

et al. 2020

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.