Multidisciplinary Data Gathering to Characterize Hydraulic Fracture Performance and Evaluate Well Spacing in the Bakken
- Apiwat Ohm Lorwongngam (Hess Corporation) | Craig Cipolla (Hess Corporation) | Christian Gradl (Hess Corporation) | Jose Gil Cidoncha (Hess Corporation) | Bruce Davis (Hess Corporation)
- Document ID
- Society of Petroleum Engineers
- SPE Hydraulic Fracturing Technology Conference and Exhibition, 5-7 February, The Woodlands, Texas, USA
- Publication Date
- Document Type
- Conference Paper
- 2019. Society of Petroleum Engineers
- 1.6 Drilling Operations, 2 Well completion, 5.6.5 Tracers, 5.1.5 Geologic Modeling, 2.5.2 Fracturing Materials (Fluids, Proppant), 0.2 Wellbore Design, 5.5 Reservoir Simulation, 2.4 Hydraulic Fracturing, 5.6 Formation Evaluation & Management, 5 Reservoir Desciption & Dynamics, 3 Production and Well Operations, 5.5.8 History Matching, 3 Production and Well Operations
- Bakken, Hydraulic Fracture characterization, Microseismic, Well spacing, Multi-Disciplinary Data Gathering
- 24 in the last 30 days
- 957 since 2007
- Show more detail
- View rights & permissions
|SPE Member Price:||USD 9.50|
|SPE Non-Member Price:||USD 28.00|
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.
|File Size||4 MB||Number of Pages||28|
Cipolla, C., Fitzpatrick, T., Williams, M.. 2011. Seismic to Simulation for Unconventional Reservoir Development. SPE 146876. Presented at the SPE Reservoir Characterization and Simulation Conference and Exhibition held in Abu Dhabi, UAE, 9-11 October 2011. https://doi.org/10.2118/146876-MS.
Cipolla, C., Gilbert, C., Sharma, A.. 2018a. Case History of Completion Optimization in the Utica. SPE 189838. Presented at the SPE Hydraulic Fracturing Technology Conference held in The Woodlands, Texas, USA, 23-25 January 2018. https://doi.org/10.2118/189838-MS.
Cipolla, C, Motiee, M, and Kechemir, A. 2018b. Integrating Microseismic, Geomechanics, Hydraulic Fracture Modeling, and Reservoir Simulation to Characterize Parent Well Depletion and Infill Well Performance in the Bakken. URTeC 2899721. Presented at the Unconventional Resources Technology Conference held in Houston, Texas, USA, 23-25 July 2018. https://doi.org/10.15530/URTEC-2018-2899721.
Dohmen, T., Zhang, J., Li, C.. 2013. A new surveillance method for delineation of depletion using microseismic, and its application to development of unconventional reservoirs. Presented at the SPE Annual Technical Conference and Exhibition. http://dx.doi.org/10.2118/166274-MS.
Dohmen, T., Blangy, J. P., and Zhang, J. 2014. Microseismic depletion delineation: Interpretation (Tulsa), 2, SG1-SG13. http://dx.doi.org/10.1190/INT-2013-0164.1.
Dohmen, T., Zhang, J., Barker, L.. 2017. Microseismic Magnitudes and b-Values for Delineating Hydraulic Fracturing and Depletion. SPE Journal. SPE-186096-PA (in press; posted 26 June 2017). https://doi.org/10.2118/186096-PA.
Mack, M., Zhang, F., Lee, B.. 2016. Geomechanical modeling of microseismic depletion delineation. SEG Technical Program Expanded Abstracts 2016: pp. 3006-3010. https://doi.org/10.1190/segam2016-13867213.1.
Weng, X., Kresse, O., Cohen, C.. 2011. Modeling of Hydraulic-Fracture-Network Propagation in a Naturally Fractured Formation. J. SPE Production & Operations, Vol. 26. No. 4, pp. 368-380, November 2011. https://doi.org/10.2118/140253-MS.