Horizontal Wells in Tight Gas Sands— A Method for Risk Management To Maximize Success

Baihly, Jason; Grant, Dee; Fan, Liping; Bodwadkar, Suhas

doi:10.2118/110067-pa

Cited by 13 publications

(6 citation statements)

References 54 publications

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“…Although it is difficult to quantify how much the lea (Baihly et al 2009;Cipolla et al 2010;Daniels et al 2007;Fisher et al 2002 and2004;King 2010;Le Calvez et al 2007;Mayerhofer et al 2005;Mayerhofer et al 2006;Mayerhofer et al 2008;Peterman et al 2005;Vincent 2009;Waters et al 2009;Warpinski et al 2005;Warpinski et al 2008;Warpinski 2009) . Therefore, using well-pairs to enable cost-effective MSM may require slightly more wells to reliably assess a low-permeability resource.…”

Section: Data Integrationmentioning

confidence: 99%

“…The combination of hydraulic fracture stimulation and horizontal drilling has enabled exploitation of vast North American shale gas resources (Arthur et al 2008;Jenkins and Boyer 2008) and improved the economics of developing some tight gas resources (Baihly et al 2009). Contacting a large reservoir surface area significantly increases hydrocarbon production rates and recovery.…”

Section: Introductionmentioning

confidence: 99%

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Reducing Exploration and Appraisal Risk in Low-Permeability Reservoirs Using Microseismic Fracture Mapping

2010

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Low-permeability reservoirs have been actively developed and considered economically viable for more than 30 years in North America, but their development has been limited elsewhere. In North America, significant infrastructure is already in place and drilling and completion costs are relatively low. The typical exploration and appraisal approach is to drill a relatively large number of low cost wells to assess economic viability. Outside North America, however, infrastructure is less developed, and costs are often higher. To achieve economical development in these areas, operators must assess resource viability by drilling as few wells as possible. The many-wells model has made international operators reluctant to explore low-permeability reservoirs in some areas. However, there is increasing interest in developing the vast resources held in tight gas, coalbed methane, and gas shale plays outside North America.The exploration and appraisal of low-permeability reservoirs or unconventional plays is significantly different than conventional reservoirs; exploration is more like appraisal, requiring pilot programs to test commerciality of these resource plays prior to embarking upon large-scale development (Hall 2007;Stabell 2007), including the effect of completion and stimulation optimization (Haskett and Brown 2005). One essential component of low-permeability reservoir development is hydraulic fracturing, which virtually all of these wells require. With the introduction of hydraulic fracture monitoring (HFM), we are now able to measure fracture geometry and complexity, which has led to major improvements in treatment designs, well completions, and field development strategies in North America. HFM applications were once focused on development and infill drilling, but they have recently shown significant value for exploration plays (primarily in gas shale). HFM measurements now allow operators to more efficiently evaluate the effectiveness of stimulation treatments and completion approaches in exploration and appraisal wells, reducing the number of wells required to assess the economic viability of low-permeability reservoirs.The application of HFM to exploration and appraisal programs outside North America could significantly accelerate the evaluation of low-permeability reservoirs, where selecting the appropriate hydraulic fracturing design and well completion strategy will be key to success. It could also accelerate the learning curve, which is essential to quickly reducing costs.

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Section: Data Integrationmentioning

confidence: 99%

Section: Introductionmentioning

confidence: 99%

Reducing Exploration and Appraisal Risk in Low-Permeability Reservoirs Using Microseismic Fracture Mapping

2010

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“…Not all hydraulic fractures in the multistage treatments are successful, though increasing the number of fractures and appropriate planning increases the chances of improved production (Baihly et al, 2009). A number of openhole completion systems are available which can isolate and hydraulically fracture up to 24 separate depth intervals.…”

Section: Multistage Fracturingmentioning

confidence: 99%

An Overview of Geomechanical Engineering Aspects of Tight Gas Sand Developments

Addis¹,

Yassir²

2010

Proceedings of SPE/DGS Saudi Arabia Section Technical Symposium and Exhibition

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Tight gas sand exploration and development is a key focus as markets around the world exploit local resources for natural gas. Tight gas sands have matrix permeabilities in the micro-Darcy range and low porosities (typically ~5%). Commercial production is possible from these reservoirs when they have a conductive natural fracture system, and when they are stimulated by hydraulic fractures. However, both the formation matrix and the natural fracture systems can be stress-sensitive, i.e. they close during depletion, reducing the gross permeabilities which pose numerous challenges to establishing sustained economic flow rates. Geomechanical engineering is central to the development of these tight gas resources: Economic flow rates and commerciality of the field developments can only be achieved by stimulation, through fracturing and dilation of the reservoir formations; imposing a "man-made" permeability network on the geological system. This paper discusses geomechanical considerations of wellbore orientation, in-situ stress systems, and connectivity between hydraulic fractures with the natural fracture system, for single and multi-staged fracturing.A major consideration during field development of tight gas sands is the stress evolution accompanying drawdown and depletion. It is now well established that reservoir pressure changes have an effect on both the stress magnitudes and the stress directions in the sub-surface. Two major consequences of the stress changes are addressed: 1) Well placement: Understanding the stress evolution accompanying depletion is central to optimally plan the well locations, infill locations, and hydraulic fracture treatments. Stress changes result in fracture re-orientation following the re-completion, and an increase in the productivity and ultimate recovery from these wells. In addition, optimally placed new infill wells may become more productive than the initial wells as a result of improved connectivity with open fracture systems.2) Sweet spot enlargement: Greater production and ultimate recovery is commonly observed where the fracture system is "relaxed" or "critically stressed". As the stresses change accompanying depletion, so can the sweet spots, with potentially negative impact on development. Geomechanical engineering can be used in field development planning to define depletion strategies which produce an optimum stress evolution in the reservoir to open up these tight formations, by enhancing the conductivity of the natural fracture system. Thus, the productive sweet spots provided by nature may be enlarged to increase the available gas resources and higher ultimate recoveries, by increasing the area available for commercial development.The geomechanical engineering aspects of tight gas sands are discussed, highlighting some potential areas where tight gas sand developments can be optimised.

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“…In recent years the application of horizontal drilling has dominated unconventional reservoir development, accessing much more reservoir volume than vertical wells and reducing the number of wells required to develop the resource. The combination of multi-stage hydraulic fracture stimulation and horizontal drilling has enabled exploitation of vast North American shale resources (Arthur et al 2008;Jenkins and Boyer 2008) and improved the economics of developing some tight gas resources (Baihly et al 2009). However, the application of horizontal drilling and the need to perform multiple hydraulic fracture treatments adds to the complexity of the completion and results in much more uncertainty when evaluating well performance and optimizing stimulation designs and completion strategies.…”

Section: Introductionmentioning

confidence: 99%

Appraising Unconventional Resource Plays: Separating Reservoir Quality from Completion Effectiveness

et al. 2011

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Appraisal wells in unconventional, very low permeability, resource plays require large hydraulic fracture treatments to assess economic viability. In many cases, drainage area and hydrocarbon recovery are defined by the areal extent and effectiveness of the hydraulic fracture treatment. To increase the drainage area and recovery per well, multiple hydraulic fracture treatments in horizontal and vertical wells are now common, resulting in more complex and expensive completions. Therefore, appraising the completion and hydraulic fracture treatment are just as important as appraising the reservoir. Unlike conventional reservoirs, the complexity and heterogeneity of unconventional resources can make reliable reservoir characterization difficult, which can result in significant uncertainty when evaluating appraisal well performance. Therefore, applying the appropriate technologies for unconventional reservoirs and a holistic approach are essential to properly separate reservoir quality from completion effectiveness. This paper details technologies and workflows that are essential to the reliable appraisal of unconventional resources, with an emphasis on appraising resources outside of North America. Due to the high cost of appraisal wells in most environments outside North America, operators must assess the viability of unconventional resources using as few wells as possible. The North American model of assessing unconventional reservoirs by drilling and completing a large number of wells may not be economically feasible in areas with insufficient hydraulic fracturing, drilling, and completion infrastructure.Due to the variability of both hydraulic fracture growth and reservoir characteristics in unconventional reservoirs, properly assessing new plays and subsequently optimizing fracture treatments and completions has historically been a -trial and error‖ process requiring a large number of wells and significant capital risk. However, efficient evaluation of stimulation treatments and completions is now possible by combining microseismic mapping and other hydraulic fracture diagnostics with advanced logs, specialized core tests, 3D seismic, and newly developed -unconventional‖ hydraulic fracture models. This holistic approach reduces the number of wells required to assess the economic viability of unconventional resources and reliably separates reservoir quality from completion effectiveness. The application of these unconventional-reservoir-specific technologies, newly developed hydraulic fracture models, and specialized workflows are illustrated using examples from North America.

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Horizontal Wells in Tight Gas Sands— A Method for Risk Management To Maximize Success

Cited by 13 publications

References 54 publications

Reducing Exploration and Appraisal Risk in Low-Permeability Reservoirs Using Microseismic Fracture Mapping

Reducing Exploration and Appraisal Risk in Low-Permeability Reservoirs Using Microseismic Fracture Mapping

An Overview of Geomechanical Engineering Aspects of Tight Gas Sand Developments

Appraising Unconventional Resource Plays: Separating Reservoir Quality from Completion Effectiveness

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