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

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.

Offset Well Design Optimization Using a Surrogate Model and Metaheuristic Algorithms: A Bakken Case Study

“…In contrast, the DFITs represent local measurements that the heterogeneity of the formation can cause. Another difference between this work and the work of Cipolla et al [16] and Fowler et al [9] is that the contribution of the Three Forks is considered in the modeling. The numerical modeling section will discuss more details about the modeling process.…”

“…Rezaei et al [15] simulated stress changes due to depletion and their effect on fracture propagation and reorientation from offset wells under different stress contrasts. Cipolla et al [16] and Fowler et al [9] modeled stress changes in a field-scale laboratory study. Morsy et al [17] reported a numerical simulation workflow to optimize offset well design through sensitivity analysis in the Wolfcamp formation.…”

“…It was mainly used to map the depleted area (an approximation to fracture geometry) and measure stress changes. More details about the interpretation can be found in Cipolla et al [16].…”

“…The time-lapse DFITs were interpreted by Cipolla et al [16] using the compliance method with an estimated closure stress of 7150 psi and a pore pressure of 5800 psi in the Middle Bakken Formation. Note that in the model calibration, only the MDD, DFIT #1, and V1 fracture treatment responses were matched.…”

Anisortopic Modeling of Hydraulic Fractures Height Growth in the Anadarko Basin

“…Where the length represents the extent of the fracture in the reservoir and the drainage area, fracture height is the vertical coverage of the HF treatment. For an appropriate design of HF jobs, fracture height estimation is essential for optimum well placement and geometry estimation [8,9].…”