Groundwater Nitrate Bioremediation Simulation of In Situ Horizontal Well by Microbial Denitrification Using PHREEQC

Abstract Large, high density fracture networks are necessary to deliver commercial production rates from sub-microdarcy permeability organic-rich shale reservoirs. Operators have increased lateral length and fracture stages as the primary means to improve well performance and, more recently, are tailoring completion techniques to local experience and reservoir-specific learning. In particular, closer fracture stage spacing or increased number of stages per well have driven improvements in well performance. Large scale adoption occurs when the change in performance is clearly linked to the reservoir-specific completion design. Horizontal well fracturing efficiency in unconventional reservoirs is notoriously poor. Numerous authors report that 40 to 60 per cent of frac stages or individual perforation clusters have been shown (albeit with highly uncertain surveillance methods) to contribute little or no production. The fracture initiation and propagation process is very complex in shale; it is affected by in-situ stress, geomechanical heterogeneity, presence of natural fractures, and completion parameters. Close cluster spacing can provide enhanced well production; however, if the spacing is too close, stress shadowing among these clusters can actually induce higher stresses, creating fracture competition. This paper presents an approach to the integration of these parameters through both state-of-the-art geological characterization and unconventional 3D hydraulic fracture modeling. We couple stochastic discrete fracture network (DFN) models of in-situ natural fractures with a state-of-the art 3D unconventional fracture simulator. The modeled fracture geometry and associated conductivity is exported into a dynamic reservoir flow model, for production performance prediction. Calibrated toolkits and workflows, underpinned by integrated surveillance including distributed temperature and acoustic fiber optic sensing (DTS/DAS), are used to optimize horizontal well completions. A case study is presented which demonstrates the technical merits and economic benefits of using this multidisciplinary approach to completion optimization.

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Application of DFIT-FBA Tests Performed at Multiple Points in a Horizontal Well for Advanced Treatment Stage Design and Reservoir Characterization

10.2118/204200-ms ◽

2021 ◽

Author(s):

Danial Zeinabady ◽

Behnam Zanganeh ◽

Sadeq Shahamat ◽

Christopher R. Clarkson

Keyword(s):

Horizontal Well ◽

Reservoir Characterization ◽

Material Balance ◽

In Situ Stress ◽

Productivity Index ◽

Multiple Points ◽

Well Productivity ◽

Balance Analysis ◽

Flowing Material

Abstract The DFIT flowback analysis (DFIT-FBA) method, recently developed by the authors, is a new approach for obtaining minimum in-situ stress, reservoir pressure, and well productivity index estimates in a fraction of the time required by conventional DFITs. The goal of this study is to demonstrate the application of DFIT-FBA to hydraulic fracturing design and reservoir characterization by performing tests at multiple points along a horizontal well completed in an unconventional reservoir. Furthermore, new corrections are introduced to the DFIT-FBA method to account for perforation friction, tortuosity, and wellbore unloading during the flowback stage of the test. The time and cost efficiency associated with the DFIT-FBA method provides an opportunity to conduct multiple field tests without delaying the completion program. Several trials of the new method were performed for this study. These trials demonstrate application of the DFIT-FBA for testing multiple points along the lateral of a horizontal well (toe stage and additional clusters). The operational procedure for each DFIT-FBA test consists of two steps: 1) injection to initiate and propagate a mini hydraulic fracture and 2) flowback of the injected fluid on surface using a variable choke setting on the wellhead. Rate transient analysis methods are then applied to the flowback data to identify flow regimes and estimate closure and reservoir pressure. Flowing material balance analysis is used to estimate the well productivity index for studied reservoir intervals. Minimum in-situ stress, pore pressure and well productivity index estimates were successfully obtained for all the field trials and validated by comparison against a conventional DFIT. The new corrections for friction and wellbore unloading improved the accuracy of the closure and reservoir pressures by 4%. Furthermore, the results of flowing material balance analysis show that wellbore unloading might cause significant over-estimation of the well productivity index. Considerable variation in well productivity index was observed from the toe stage to the heel stage (along the lateral) for the studied well. This variation has significant implications for hydraulic fracture design optimization, particularly treatment pressures and volumes.

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Design and Numerical Simulation of In-Situ Pyrolysis of Oil Shale Through Horizontal Well Fracturing with Nitrogen Injection

International Journal of Heat and Technology ◽

10.18280/ijht.390210 ◽

2021 ◽

Vol 39 (2) ◽

pp. 417-423

Author(s):

Pengfei Jiang ◽

Danlei Zhang ◽

Bin Li ◽

Chao Song

Keyword(s):

Heat Transfer ◽

High Temperature ◽

Oil Shale ◽

Horizontal Well ◽

High Energy ◽

Cross Sectional Area ◽

Sectional Area ◽

Cross Sectional ◽

Shale Formation

An in-situ pyrolysis technology was proposed for shallow oil shale: drilling horizontal wells to the oil shale formation, connecting the horizontal well sections through hydraulic fracturing, injecting nitrogen from the surface to bottomhole, heating up the nitrogen to a high temperature at the bottom, and directly using the high-temperature nitrogen for oil shale pyrolysis. Then, a mathematical model was established for the heat transfer within the oil shale, and a simplified physical model was created for in-situ pyrolysis of oil shale, and used to simulate the heat transfer process. The simulation results show that, with the extension of heating time, the area of effectively pyrolyzed oil shale formation took up an increasingly large proportion of the total cross-sectional area of the formation; however, the increase of the pyrolysis area ratio was rather slow, and the temperature was unevenly distributed in the formation after a long duration of heating. Therefore, the 300d in-situ heating was split into two stages: 250d of heating in the heating well and 50d of heating in the production well. The two-stage heating maximized the heating area of oil shale, and heated 57% of the cross-sectional area up to 400℃, ensuring the effectiveness of pyrolysis. Moreover, this heating scheme ensured an even distribution of temperature in oil shale formation, a high energy utilization, and a desirable heating effect.

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