3D Modeling of Multistage Hydraulic Fractures and Two-Way Coupling Geomechanics: Fluid Flow Simulation of a Horizontal Well in the Nikanassin Tight Gas Formation "Canada"

2012 ◽  
Author(s):  
Laureano Gonzalez ◽  
Gaisoni Nasreldin ◽  
Jose A. Rivero ◽  
Peter Welsh ◽  
Roberto Aguilera
Keyword(s):  
Fluid Flow ◽  
3D Modeling ◽  
Horizontal Well ◽  
Flow Simulation ◽  
Hydraulic Fractures ◽  
Tight Gas ◽  
Gas Formation ◽  
Tight Gas Formation

3D Modeling of Multistage Hydraulic Fractures and Two-Way-Coupling Geomechanics/Fluid-Flow Simulation of a Horizontal Well in the Nikanassin Tight Gas Formation, Western Canada Sedimentary Basin

2014 ◽  
Vol 17 (02) ◽  
pp. 257-270 ◽  
Author(s):  
Laureano Gonzalez ◽  
Gaisoni Nasreldin ◽  
Jose Rivero ◽  
Pete Welsh ◽  
Roberto Aguilera
Keyword(s):  
Hydraulic Fracturing ◽  
Horizontal Well ◽  
Three Dimensions ◽  
Hydraulic Fractures ◽  
Western Canada ◽  
Tight Gas ◽  
Western Canada Sedimentary Basin ◽  
Gas Formation ◽  
Tight Gas Formation ◽  
Canada Sedimentary Basin

Summary Unconventional gas is stored in extensive areas known as basin-centered continuous-gas accumulations. Although the estimated worldwide figures differ significantly, the consensus among the studies relating to unconventional gas resources is that the volumes are gigantic. However, the low permeability in these types of reservoirs usually results in a very low recovery factor. To help unlock these resources, this paper presents a new and more accurate way of simulating multistage hydraulic fracturing in horizontal wells in three dimensions by use of single- and dual-porosity reservoir models. In this approach, the geometry (not necessarily symmetric) and orientation of the multiple hydraulic fractures are driven by the prevailing stress state in the drainage volume of the horizontal well. Once the hydraulic-fracturing job is accurately modeled in three dimensions, two-way geomechanical coupling is used to history match the produced gas from a horizontal well drilled in the Nikanassin naturally fractured tight gas formation of the Western Canada Sedimentary Basin (WCSB). Traditionally, the most widely used approaches have their roots in semianalytical calculations simplifying the fracturing system to a planar feature propagating symmetrically away from a line source of injection. In contrast, the computed results presented in this study show that the incorporation of geomechanical effects gives a more realistic representation of the orientation and geometry of hydraulic fractures. Reduction in permeability of the natural and hydraulic fractures because of pressure depletion results in more-realistic production predictions compared with the case in which geomechanical effects are ignored. The telling conclusion, in light of the computed results, is that the field of hydraulic fracturing provides an object lesson in the need for coupled 3D geomechanical approaches. The method presented in this paper will help to improve gas rates and recoveries from reservoirs with permeability values in the nanodarcy scale.

Utilizing Pseudo Well Connections to Simulate Multi-Stage Hydraulic Fracturing - Example Based On the Study of a Tight Gas Asset

2021 ◽  
Author(s):  
Aamir Lokhandwala ◽  
Vaibhav Joshi ◽  
Ankit Dutt
Keyword(s):  
Hydraulic Fracturing ◽  
Oil And Gas ◽  
Flow Simulation ◽  
Oil And Gas Industry ◽  
Development Plan ◽  
Hydraulic Fractures ◽  
Tight Gas ◽  
Gas Field ◽  
Field Development ◽  
Fracture Modeling

Abstract Hydraulic fracturing is a widespread well stimulation treatment in the oil and gas industry. It is particularly prevalent in shale gas fields, where virtually all production can be attributed to the practice of fracturing. It is also used in the context of tight oil and gas reservoirs, for example in deep-water scenarios where the cost of drilling and completion is very high; well productivity, which is dictated by hydraulic fractures, is vital. The correct modeling in reservoir simulation can be critical in such settings because hydraulic fracturing can dramatically change the flow dynamics of a reservoir. What presents a challenge in flow simulation due to hydraulic fractures is that they introduce effects that operate on a different length and time scale than the usual dynamics of a reservoir. Capturing these effects and utilizing them to advantage can be critical for any operator in context of a field development plan for any unconventional or tight field. This paper focuses on a study that was undertaken to compare different methods of simulating hydraulic fractures to formulate a field development plan for a tight gas field. To maintaing the confidentiality of data and to showcase only the technical aspect of the workflow, we will refer to the asset as Field A in subsequent sections of this paper. Field A is a low permeability (0.01md-0.1md), tight (8% to 12% porosity) gas-condensate (API ~51deg and CGR~65 stb/mmscf) reservoir at ~3000m depth. Being structurally complex, it has a large number of erosional features and pinch-outs. The study involved comparing analytical fracture modeling, explicit modeling using local grid refinements, tartan gridding, pseudo-well connection approach and full-field unconventional fracture modeling. The result of the study was to use, for the first time for Field A, a system of generating pseudo well connections to simulate hydraulic fractures. The approach was found to be efficient both terms of replicating field data for a 10 year period while drastically reducing simulation runtime for the subsequent 10 year-period too. It helped the subsurface team to test multiple scenarios in a limited time-frame leading to improved project management.

Multistage Hydrocarbon-Based Fracturing in Tight Gas Formation (Russian)

2020 ◽  
Author(s):  
Vladimir Astafyev ◽  
Mikhail Lushev ◽  
Alexey Mitin ◽  
Alexey Plotnikov ◽  
Evgenii Mironov ◽  
...  
Keyword(s):  
Tight Gas ◽  
Gas Formation ◽  
Tight Gas Formation

Optimal Designs of Well Pattern for the Development of Tight Gas Reservoirs (TGRs)

2016 ◽  
Vol 9 (1) ◽  
pp. 77-90
Author(s):  
Jiao Yuwei ◽  
Xia Jing ◽  
Yan Jianye ◽  
Xu Daicai
Keyword(s):  
Horizontal Well ◽  
Optimal Designs ◽  
Hydraulic Fractures ◽  
Stress Effect ◽  
Tight Gas ◽  
Gas Reservoirs ◽  
Vertical Well ◽  
Fractured Horizontal Well ◽  
Well Pattern ◽  
Reservoir Conditions

Both horizontal well and fractured-horizontal well have been widely used to develop TGRs. However, the costs of horizontal well and fractured-horizontal well are much higher than the vertical well. Therefore, it is necessary to consider the reservoir conditions for evaluating the potential benefit when choosing well pattern or designing well parameters. In this paper, a simulator of simulating the development of TGRs including slippage flow and stress dependence in matrix, and high-velocity non-Darcy flow and stress effect in hydraulic fractures was firstly developed. Then, it was used to study the development effects of different TGRs using different well patterns and well parameters. Based on the simulation results, the incremental ratio models of horizontal well to vertical well and fractured-horizontal well to horizontal well were achieved. These models can be used to predict the incremental production using horizontal well or fractured-horizontal well. We also obtained the plates of choosing well pattern and designing the corresponding parameters to achieve a good profit in the field.

Exploration of HPHT Tight Gas Formation: First Application of Propped Fracturing in the Offshore Gulf

2015 ◽  
Author(s):  
Al Ameri F. ◽  
Al Awadhi F. ◽  
Abbott J. ◽  
Akbari A. ◽  
Daniels J.L.
Keyword(s):  
Tight Gas ◽  
Gas Formation ◽  
Tight Gas Formation

Geological Model Coupled with Geomechanics Makes an Impact on Fracturing Stimulation and Field Development Strategy of a Tight Gas Formation in the Sultanate of Oman

2015 ◽  
Author(s):  
Kevin Bate ◽  
Mauricio Lane ◽  
Alexey Moiseenkov ◽  
Sergey Nadezhdin
Keyword(s):  
Development Strategy ◽  
Fracture Propagation ◽  
Radioactive Tracer ◽  
Hydraulic Fractures ◽  
Tight Gas ◽  
Reservoir Properties ◽  
Gas Field ◽  
Field Development ◽  
Tight Gas Formation ◽  
The Individual

Abstract Appraisal drilling of a recently discovered Cambrian-aged gas field in Oman is indicating that the field may have significant amounts of gas locked in a challenging deep, hot, and highly pressured reservoir environment. The low porosity and permeability values of the Amin reservoir allow the classification of the reservoir as a tight gas sand. The variability of reservoir properties, both spatially and vertically, makes it difficult to standardize perforation and fracture stimulation design which, in turn, complicates delineation of a development plan for the project. One of the difficulties relates to uncertainty in vertical propagation of hydraulic fractures. Fracture height based on evaluation of radioactive tracer logs indicates that vertical barriers to fracture propagation may relate to specific geologic zones in the reservoir. The mapping of the reservoir zones into undeveloped areas of the field would allow selection of primary and secondary production targets based on the specific physical properties of the individual zones. To assume that no barrier to fracture propagation exists between separate production units may lead to attempts to stimulate them synchronously, which would be disadvantageous for several reasons, such as premature screenouts and incomplete coverage of gas-bearing layers. Reserves booking and allocation can also be jeopardized should the fractures propagate into undesired zones.

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