An Integrated Reservoir Modeling Case Study to Simulate Multi-Stage Hydraulically Fractured Horizontal Wells, Based on Seismic, Petrophysical, and Geological Data for Pinedale Tight Gas Fluvial Reservoir

Gaddipati, Manohar; Firincioglu, Tuba; LaBarre, E.; Yang, Yongqiang; Wahl, Daniel E.; Clarke, Patricia; Long, A.; Ozgen, Cetin

doi:10.15530/urtec-2020-2582

Cited by 2 publications

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“…By estimating the fluid types and their volume as well as the rock and mineral types, petrophysical studies will help to provide comprehensive information about the reservoir. Therefore, in various types of research studies, including reservoir characterization [5][6][7][8][9][10][11][12][13], hydraulic fracturing simulation/operation [14][15][16][17][18][19][20][21][22][23], and building, evaluating, and controlling numerical models [24,25], petrophysical parameters play a vital role. Porosity, permeability, and water saturation, which are considered as three main reservoir petrophysical properties, are provided by core or well-logging data.…”

Section: Introductionmentioning

confidence: 99%

Joint Application of Diagenetic, Petrophysical and Geomechanical Data for Selecting Hydraulic Fracturing Candidate Zone

Bakhshi¹,

Shahrabadi²,

Golsanami

et al. 2021

Int. J. Petrol. Technol.

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The more comprehensive information on the reservoir properties will help to better plan drilling and design production. Herein, diagenetic processes and geomechanical properties are notable parameters that determine reservoir quality. Recognizing the geomechanical properties of the reservoir as well as building a mechanical earth model play a strong role in the hydrocarbon reservoir life cycle and are key factors in analyzing wellbore instability, drilling operation optimization, and hydraulic fracturing designing operation. Therefore, the present study focuses on selecting the candidate zone for hydraulic fracturing through a novel approach that simultaneously considers the diagenetic, petrophysical, and geomechanical properties. The diagenetic processes were analyzed to determine the porosity types in the reservoir. After that, based on the laboratory test results for estimating reservoir petrophysical parameters, the zones with suitable reservoir properties were selected. Moreover, based on the reservoir geomechanical parameters and the constructed mechanical earth model, the best zones were selected for hydraulic fracturing operation in one of the Iranian fractured carbonate reservoirs. Finally, a new empirical equation for estimating pore pressure in nine zones of the studied well was developed. This equation provides a more precise estimation of stress profiles and thus leads to more accurate decision-making for candidate zone selection. Based on the results, vuggy porosity was the best porosity type, and zones C2, E2 and G2, having suitable values of porosity, permeability, and water saturation, showed good reservoir properties. Therefore, zone E2 and G2 were chosen as the candidate for hydraulic fracturing simulation based on their E (Young’s modulus) and ν (Poisson’s ratio) values. Based on the mechanical earth model and changes in the acoustic data versus depth, a new equation is introduced for calculating the pore pressure in the studied reservoir. According to the new equation, the dominant stress regime in the whole well, especially in the candidate zones, is SigHmax>SigV>Sighmin, while according to the pore pressure equation presented in the literature, the dominant stress regime in the studied well turns out to be SigHmax>Sighmin>SigV.

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Section: Introductionmentioning

confidence: 99%

Joint Application of Diagenetic, Petrophysical and Geomechanical Data for Selecting Hydraulic Fracturing Candidate Zone

Bakhshi¹,

Shahrabadi²,

Golsanami

et al. 2021

Int. J. Petrol. Technol.

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Gas Injection Pilot Design Simulation Model in Eagle Ford

Basbug¹,

Sarak²,

Firincioglu³

et al. 2022

SPE Improved Oil Recovery Conference

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The primary objectives of this study are to design a gas injection pilot in the Eagle Ford and to estimate the benefits of gas injection under different operational scenarios. This pilot design study entails the construction of multiple reservoir simulation models to understand the hydraulic fracturing and flow dynamics of multiple wells and gas injection operations in the Eagle Ford. Two DSUs with multiple hydraulically fractured wells were studied to achieve the proposed objectives. One of the DSUs was identified as the main study area to design a huff-and-puff gas injection pilot. Having an existing gas injection operation, the other DSU was selected to improve our understanding of the physics associated with gas injection. A dual porosity numerical reservoir simulation model coupled with geo-mechanics was built to replicate the historical well performances of the pilot area using a sophisticated numerical reservoir simulator. Another dual porosity simulation model was constructed to assimilate the existing huff-and-puff performance of the second DSU in which data was only publically available. The methodology used in this study integrates the hydraulic fracturing process, multi-phase flow, geo-mechanics, and proppant transport within the reservoir simulation. The simulation model was calibrated to match the historical hydraulic fracture treatment, fluid flow back and post-stimulation production. The proppant entrapment and migration from child well to the parent well was captured. The calibrated simulation model was then utilized to design a huff-and-puff gas injection pilot. Learnings and observations obtained from modeling of the existing gas injection operation in the second DSU were integrated into the pilot model. Additional sensitivity runs were performed to examine the potential benefits of gas injection under different operational scenarios. The calibration results indicated that the stimulated rock volume geometries of pilot study wells vary based on their completion practices. The historically observed well interference and frac hits between parent and child wells were captured by establishing a proper connectivity between wells during calibration. Proppant entrapment and movement of the proppant impacted the well performance. The results showed that significant amount of depletion leads to considerable matrix permeability reduction around wells. The most important knowledge gained from the calibration of the second DSU with huff-and-puff data is the identification of reservoir model characteristics that have the largest impact on the huff-and-puff performance. This study allows us to identify opportunities to design and improve huff-and-puff operation as well as estimating benefits of gas injection under different operational scenarios. The utilized technology in this study is unique and novel as it solves the geomechanics and flow in a single process. Proppant flow and entrapment was captured successfully. The multi-well calibration of the simulation model provides physics-based explanations for the historical well performances in the Eagle Ford.

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An Integrated Reservoir Modeling Case Study to Simulate Multi-Stage Hydraulically Fractured Horizontal Wells, Based on Seismic, Petrophysical, and Geological Data for Pinedale Tight Gas Fluvial Reservoir

Cited by 2 publications

References 0 publications

Joint Application of Diagenetic, Petrophysical and Geomechanical Data for Selecting Hydraulic Fracturing Candidate Zone

Joint Application of Diagenetic, Petrophysical and Geomechanical Data for Selecting Hydraulic Fracturing Candidate Zone

Gas Injection Pilot Design Simulation Model in Eagle Ford

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