Resolving Production Trends in Shale Reservoirs—An Eagle Ford Case Study from Localized Reservoir Characterization to Basin Understanding

Moncada, Katharine; Atwood, Keith; Altman, R.G.; Malpani, Raj; Indriati, Shirley; Clayton, Richard

doi:10.1190/urtec2013-012

Cited by 5 publications

(4 citation statements)

References 10 publications

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“…Quirein et al (2010), Passey et al (2010) and Moncada et al (2013) characterized shale reservoir properties from geological and petrophysical perspectives. Jiang and Spikes (2013), Johnson et al (2013) and Kumar et al (2014) applied advanced imaging and inversion techniques to derive key rock properties.…”

Section: Introductionmentioning

confidence: 99%

Integrated Petrophysical and Geophysical Analysis on Identifying Eagle Ford Sweet Spots

Chen¹,

Kumar²,

Uerling³

et al. 2015

Unconventional Resources Technology Conference

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The advanced drilling and hydraulic fracturing technologies have greatly increased the resource exploitation in the unconventional Eagle Ford shale play. Petrophysical studies found that the resources formed a tight correlation with the estimated production volume in the high quality shale intervals, when the operations are similar. Seismic tools were utilized to estimate such rock properties. Seismic horizon interpretation estimated the reservoir thickness. Seismic inversion was utilized for acoustic impedance and seismic net pay for "net" thickness prediction with higher porosity. The calculated seismic net pay agreed with the well log data. Like petrophysical analysis, the seismic net pay also formed a strong correlation with the production volume and has been used to identify sweet spots for future wells in the Eagle Ford shale. Figure 1-Eagle Ford Shale Play, Western Gulf Basin, South Texas. The seismic survey is located in the western portion of Eagle Ford play (marked with a star) in South Texas. Source: Energy Information Administration.

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Section: Introductionmentioning

confidence: 99%

Integrated Petrophysical and Geophysical Analysis on Identifying Eagle Ford Sweet Spots

Chen¹,

Kumar²,

Uerling³

et al. 2015

Unconventional Resources Technology Conference

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“…Moncada et al (2013) showed a case study that two laterals from the Eagle Ford shale had very similar reservoir quality (RQ) but were on very different production trends (Fig.2). Well B has a cumulative production three times that Well A despite having a RQ index lower than Well A.…”

Section: Introductionmentioning

confidence: 99%

“…If such a hidden driver can't be understood, then we will likely not be able to make more successful Well B type completions repeatedly. Moncada et al (2013) interpreted that it was likely the existence of natural fractures as the main reason that made Well B outperform Well A. This will still not help us to be able to drill another Well B before we do some serious home work to understand the characterization of the natural fracture systems in the field.…”

Section: Introductionmentioning

confidence: 99%

Natural Fractures in Unconventional Shale Reservoirs in US and their Roles in Well Completion Design and Improving Hydraulic Fracturing Stimulation Efficiency and Production

2014

SPE Annual Technical Conference and Exhibition

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Most of the shale reservoirs in US land are naturally fractured. The fracture intensity and types vary from one shale to another. Even within the same shale in the same field, the heterogeneity of fracture intensity can be often expected to be high in a horizontal well. The current popular geometrical completion design can potentially ignore the existence of natural fractures. Hence, maximizing stimulation efficiency without understanding existing natural fractures can be a challenge. In this paper, study was made of the majority of the published case studies related to natural fractures in the US shales in the last 20 years. The evidence of natural fractures from either outcrops or subsurface data, i.e. core, borehole images, or other data is summarized for each studied shale. The latest studies show that the hydraulic fracture propagation can be strongly influenced by existing natural fractures regardless of whether they are open or closed. The roles of existing fractures in the shales include: 1) providing enhanced reservoir permeability for improved productivity if they are open and effectively connected by hydraulic fractures; 2) promoting much better fracturing network complexity regardless of whether they are open or closed prior to the stimulation; 3) giving possible negative impact sometimes, i.e. high water cut, if they are connected with wet zones below or above the reservoirs. It can be concluded that engineered completion designs that employ accurate knowledge of natural fracture data, in-situ stresses, and other reservoir and completion quality indicators as inputs can provide opportunities for enhancing stimulation efficiency and fracturing network complexity. This in turn can lead to better connectivity to a larger reservoir volume and access to more drainage area in the shales.

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“…The SRV permeability was used to represent the enhanced conductivity volume as a result of the secondary complex fractures activated during the stimulation treatment. It is assumed that the individual fractures link up to form a single connected fracture network with an effective permeability greater than the background matrix (Suliman et al, 2013;Rubin, 2010;Moncada et al, 2013). is evaluated after five years of production; the specific parameters used to calculate the NPV are discussed further in the next chapter.…”

Section: Chapter 6 Sensitivity Analysismentioning

confidence: 99%

Coupled Geomechanics and Fluid Flow Model for Production Optimization in Naturally Fractured Shale Reservoirs

Curnow

Tutuncu

2015

SEG Technical Program Expanded Abstracts 2015

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The benefits of hydraulic fracturing horizontal wells in unconventional reservoirs for production enhancement are evident; however, the best methods to truly increase recovery efficiency through these stimulations are still under great examination.Analogous to how operators and service companies discovered that Barnett-style slickwater treatments were not successful in all reservoirs, companies are beginning to recognize the importance of engineered stimulations, specifically in regard to geomechanics. Rather than perforating for only production purposes, hydraulic fracturing design has now turned its focus to perforating for reservoir rock stimulation.Enhanced fracture network complexity through induced fractures greatly increases the contact area and reservoir drainage for maximum productivity. However, to accomplish the stimulation of both primary and secondary fracture networks, the coupled behaviors of geomechanics and fluid flow in response to the hydraulic fracturing operations must be considered.This research details the development of a coupled geomechanics and fluid flow model for the purpose of hydraulic fracture design optimization through the evaluation of different stimulation patterns. The patterns under consideration include the Zipper, Texas Two-Step, and Modified Zipper designs. Furthermore within these patterns, the well locations and hydraulic fracture properties are analyzed to determine the most ideal design for a shale oil reservoir based on recovery efficiency and economic viability.

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Resolving Production Trends in Shale Reservoirs—An Eagle Ford Case Study from Localized Reservoir Characterization to Basin Understanding

Cited by 5 publications

References 10 publications

Integrated Petrophysical and Geophysical Analysis on Identifying Eagle Ford Sweet Spots

Integrated Petrophysical and Geophysical Analysis on Identifying Eagle Ford Sweet Spots

Natural Fractures in Unconventional Shale Reservoirs in US and their Roles in Well Completion Design and Improving Hydraulic Fracturing Stimulation Efficiency and Production

Coupled Geomechanics and Fluid Flow Model for Production Optimization in Naturally Fractured Shale Reservoirs

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