A Conceptual Shale Gas Field Development Plan for the Lower Jurassic Posidonia Shale in The Netherlands

2014 ◽  
Author(s):  
Bas Brouwer ◽  
Berend C Scheffers ◽  
Michiel Harings ◽  
Raymond Godderij ◽  
Maarten-Jan Brolsma ◽  
...  
Keyword(s):  
The Netherlands ◽  
Shale Gas ◽  
Lower Jurassic ◽  
Development Plan ◽  
Gas Field ◽  
Field Development ◽  
Posidonia Shale

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.

scholarly journals Technoeconomic analysis of shale gas gross split contract in Naintupo Formation, Tarakan Basin

2018 ◽  
Vol 67 ◽  
pp. 01003
Author(s):  
Wike Widyanita ◽  
Nelson Saksono
Keyword(s):  
Shale Gas ◽  
Supply And Demand ◽  
Economic Indicator ◽  
High Flow ◽  
Low Flow ◽  
Flow Profile ◽  
Gas Field ◽  
Field Development ◽  
Technoeconomic Analysis ◽  
Decline Curves

The deficit of natural gas supply and demand could be minimized by discovering new reserves in conventional or unconventional reservoir. Shale gas potential in Indonesia was estimated 574 TCF and Naintupo Formation in Tarakan Basin had 5 TCF of technically recoverable reserve with 35 TCF risked gas-in-place. This study would discuss technoeconomic aspect of shale gas field development in Naintupo Formation, Tarakan Basin using gross split contract scheme. Three flow profiles would be developed by using Arps hyperbolic decline curves, consist of low flow profile with initial production (qi) of 150 mmcf/mo, medium (qi = 250 mmcf/mo) and high flow profile (qi = 350 mmcf/mo). Costs estimation were based on benchmarking cost of developed shale gas field in United States and nearby oil/gas field development in Tarakan Basin. Economic analysis showed that medium and high flow profile gave positive economic indicator marked by positive NPV and IRR>10%. Sensitivity analysis showed that flow profile gave more effect in NPV and IRR increased than the gas price. In order to develop positive NPV with discount rate of 10%, it is required to sell shale gas at $6.52/MMBTU in high flow profile or $8.42/MMBTU in medium flow profile.

Multi‐period design and planning model of shale gas field development

AIChE Journal ◽  
2021 ◽  
Author(s):  
Zedong Peng ◽  
Can Li ◽  
Ignacio E. Grossmann ◽  
Kysang Kwon ◽  
Sukjoon Ko ◽  
...  
Keyword(s):  
Shale Gas ◽  
Planning Model ◽  
Gas Field ◽  
Field Development

scholarly journals 3D basin and petroleum system modelling of the NW German North Sea (Entenschnabel)

2017 ◽  
Vol 8 (1) ◽  
pp. 67-86 ◽  
Author(s):  
Jashar Arfai ◽  
Rüdiger Lutz
Keyword(s):  
Heat Flow ◽  
North Sea ◽  
Late Jurassic ◽  
Upper Jurassic ◽  
Lower Jurassic ◽  
Petroleum System ◽  
Source Rocks ◽  
System Modelling ◽  
Gas Field ◽  
Posidonia Shale

Abstract3D basin and petroleum system modelling covering the NW German North Sea (Entenschnabel) was performed to reconstruct the thermal history, maturity and petroleum generation of three potential source rocks, namely the Namurian–Visean coals, the Lower Jurassic Posidonia Shale and the Upper Jurassic Hot Shale.Modelling results indicate that the NW study area did not experience the Late Jurassic heat flow peak of rifting as in the Central Graben. Therefore, two distinct heat flow histories are needed since the Late Jurassic to achieve a match between measured and calculated vitrinite reflection data. The Namurian–Visean source rocks entered the early oil window during the Late Carboniferous, and reached an overmature state in the Central Graben during the Late Jurassic. The oil-prone Posidonia Shale entered the main oil window in the Central Graben during the Late Jurassic. The deepest part of the Posidonia Shale reached the gas window in the Early Cretaceous, showing maximum transformation ratios of 97% at the present day. The Hot Shale source rock exhibits transformation ratios of up to 78% within the NW Entenschnabel and up to 20% within the Central Graben area. The existing gas field (A6-A) and oil shows in Chalk sediments of the Central Graben can be explained by our model.

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