Using Production Log to Calibrate Horizontal Wells in Reservoir Simulation

2007 ◽  
Author(s):  
Yuandong Wang ◽  
Jaime Eduardo Moreno ◽  
Jack Hagop Harfoushian
Keyword(s):  
Reservoir Simulation ◽  
Horizontal Wells

Technology Application on Two-Stage Model of Horizontal Well in the Block Oilfield

2014 ◽  
Vol 508 ◽  
pp. 169-172
Author(s):  
Hong Wei Liu
Keyword(s):  
Numerical Simulation ◽  
Reservoir Simulation ◽  
Trajectory Optimization ◽  
Horizontal Well ◽  
Horizontal Wells ◽  
Optimization Methods ◽  
Simulation Methods ◽  
Stage Model ◽  
Technology Application ◽  
Production Parameters

The technology of horizontal well emerges in 1970s-1980s, mainly from the standard length of the horizontal well, the reasonable level in the reservoir, trajectory optimization of the level to ensure the level and get the best production results. Numerical simulation is the most effective and accurate way to optimize the parameters of horizontal well, to understand the geology in this article, based on the use of reservoir simulation methods, looking for the benefit of regional development of horizontal well, and the Optimization methods to determine the length of the horizontal wells and production parameters, design two-level horizontal well in TZ422 oilfield of Tower, and achieved good results.

Impediments to Refracturing Success in Shale Reservoirs

2021 ◽  
Author(s):  
Clay Kurison
Keyword(s):  
Hyperbolic Equation ◽  
Reservoir Simulation ◽  
Analytical Techniques ◽  
Horizontal Wells ◽  
B Value ◽  
Hydraulic Fractures ◽  
Fracturing Fluid ◽  
Minimal Impact ◽  
Wellhead Pressure ◽  
The Matrix

Abstract Stimulations in early horizontal wells in most shale plays are characterized by few and widely spaced perforation clusters, and low amounts of injected fracturing fluid and proppant. Low recovery from these wells has motivated refracturing although outcomes have been interpreted to range from successful to minimal impact based on operator specific evaluations. To tailor available technologies and improve quantification of upsides, there is need for mapping the spatial distribution of remaining resources and developing simpler but reliable analytical techniques. In this study, hydraulic fractures were assumed to be planar in a matrix with low porosity and ultra-low permeability. Consideration of natural fractures and their interaction with stimulation fluids led to addition of distributed fracture networks adjacent to the planar hydraulic fractures to define the composite fracture corridors. A sector model with the aforementioned architecture was used in reservoir simulation to investigate induced temporal and spatial drainage. These findings were used to explain the efficacy of widely used refracturing techniques and how post-refracturing reservoir response can be analyzed. Results from reservoir simulation showed remaining reserves were in the matrix between earlier placed hydraulic fractures aligned along initial perforation clusters, and beyond tips of hydraulic fractures. Upside from refracs could come from creation of new fractures in the matrix between earlier placed fractures and extension of tips of early fractures into virgin matrix. Assessment of these scenarios found the former to be optimal although depletion and existing perforations would limit the stimulation efficiency of new perforations. The second scenario would require large volumes of fracturing fluid to re-initiate fracture propagation. Yet this could trigger interference with offsets or affect drilling and stimulation of planned wells in adjacent acreage. For treatment efficiency, re-casing horizontal wells with competent liners and use of coiled tubing with straddle packers appears a better solution for bypassing old perforations. For the near wellbore and far field, re-stimulating new perforations at low injection rates could allow extension of fractures in virgin matrix surrounded by depleted strata. Real-time surveillance would be essential for mapping flow paths of refracturing fluid. For assessment of refracturing, actual and simulated flow exhibited persistent linear flow (PLF) that could be matched by Arps hyperbolic equation with a b value of 2. Incorporation of a novel fracture geometry factor (FGF) yielded an Arps-based equation that was tested on North American shale refracturing cases that often use post-treatment peak rate and wellhead pressure as measures of success. This study identified factors hindering the success of refracturing and proposed a modified Arps hyperbolic equation to analyze refracturing production data.

Reservoir Simulation of Horizontal Wells in the Helder Field

1991 ◽  
Vol 43 (08) ◽  
pp. 906-913 ◽  
Author(s):  
Bashir M. Zagalal ◽  
Patrick J. Murphy
Keyword(s):  
Reservoir Simulation ◽  
Horizontal Wells

scholarly journals Analysis of Spatial Distribution Pattern of Reservoir Petrophysical Properties for Horizontal Well Performance Evaluation-A Case Study of Reservoir X

2019 ◽  
Vol 12 (1) ◽  
pp. 1-13 ◽  
Author(s):  
Aidoo Borsah Abraham ◽  
Annan Boah Evans ◽  
Brantson Eric Thompson
Keyword(s):  
Spatial Distribution ◽  
Distribution Pattern ◽  
Reservoir Simulation ◽  
Horizontal Well ◽  
Oil Production ◽  
Horizontal Wells ◽  
Spatial Distribution Pattern ◽  
Petrophysical Properties ◽  
Well Performance ◽  
Reservoir Performance

Introduction: Building a large number of static models to analyze reservoir performance is vital in reservoir development planning. For the purpose of maximizing oil recovery, reservoir behavior must be modelled properly to predict its performance. This requires the study of the variation of the reservoir petrophysical properties as a function of spatial location. Methods: In recent times, the method used to analyze reservoir behavior is the use of reservoir simulation. Hence, this study seeks to analyze the spatial distribution pattern of reservoir petrophysical properties such as porosity, permeability, thickness, saturation and ascertain its effect on cumulative oil production. Geostatistical techniques were used to distribute the petrophysical properties in building a 2D static model of the reservoir and construction of dynamic model to analyze reservoir performance. Vertical to horizontal permeability anisotropy ratio affects horizontal wells drilled in the 2D static reservoir. The performance of the horizontal wells appeared to be increasing steadily as kv/kh increases. At kv/kh value of 0.55, a higher cumulative oil production was observed compared to a kv/kh ratio of 0.4, 0.2, and 0.1. In addition, horizontal well length significantly affects cumulative oil production of the petroleum reservoir studied. Results: At kv/kh of 0.55, the results of the analysis showed a rapid decrement in cumulative oil production as the horizontal well length decreases. Considering horizontal well length of 3000 ft, 2000 ft, and 1500 ft, a minimum cumulative oil production was obtained from a horizontal well length of 1500 ft. Conclusion: The geostatistical and reservoir simulation methods employed in this study will serve as an insight in analyzing horizontal well performance.

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