Improving Production in the Eagle Ford Shale With Fracture Modeling, Increased Fracture Conductivity, and Optimized Stage and Cluster Spacing Along the Horizontal Wellbore

Bazan, Lucas W.; Larkin, Samuel Dale; Lattibeaudiere, Michael G.; Palisch, Terrence T.

doi:10.2118/138425-ms

Cited by 58 publications

(24 citation statements)

References 19 publications

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“…al, 2003), (Burgoyne & Clements, 2014) whereas on a shorter scale of days it appears as a smooth plateau (Clarkson & Qanbari, 2016). The CBM production type curves have a longer ramp time to peak flow than the shale gas examples which appear to be almost instantaneous (Mavor et al 2003), (Burgoyne & Clements, 2014), (Clarkson & Qanbari, 2016), (Bazan et al, 2010), (Lewis & Hughes, 2008). Post peak flow, the reservoir production M A N U S C R I P T…”

Section: Description Of a Gas Well Flow Type Curvementioning

confidence: 98%

Developing synthetic reservoir type curve model for use in evaluating surface facility and gathering pipe network designs

Dennis

2017

Journal of Natural Gas Science and Engineering

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Please cite this article as: Dennis, M., Developing synthetic reservoir type curve model for use in evaluating surface facility and gathering pipe network designs, Journal of Natural Gas Science & Engineering (2017), doi: 10.1016/j.jngse.2017 This is a PDF file of an unedited manuscript that has been accepted for publication. As a service to our customers we are providing this early version of the manuscript. The manuscript will undergo copyediting, typesetting, and review of the resulting proof before it is published in its final form. Please note that during the production process errors may be discovered which could affect the content, and all legal disclaimers that apply to the journal pertain. M A N U S C R I P T A C C E P T E D ACCEPTED MANUSCRIPT AbstractSurface facilities and unconventional gas gathering networks are typically designed to collect gas from a large number of wells to a central location. The unit operations that make up the surface network need to be installed before the wells are producing and thus need to be sized on predicted performance rather than actual performance which is not known until production data is available. This means each reservoir's production profile which is based on uncertain input parameters and imperfect reservoir models forms the sizing basis for the surface facilities.In this study a method is developed to generate synthetic reservoir flow type curves based on a set of input parameters that is independent of reservoir parameters. The main qualitative characteristics of an unconventional gas reservoir type curve are described such as gas ramp to peak, peak gas flow and production decline, along with the discontinuities and variations from expected performance seen in operating trends. The synthetic type curve proposed in this work can be parameterised to mimic these characteristics, along with a well deliverability mechanism and subsurface communication between wells.The method of being able to describe a type curve by means of input parameterisation allows an unconventional gas surface facility of gathering pipe network and in-field booster compressors to be designed against many sets of synthetic type curves rapidly generated by randomisation of those input parameters.

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Section: Description Of a Gas Well Flow Type Curvementioning

confidence: 98%

Developing synthetic reservoir type curve model for use in evaluating surface facility and gathering pipe network designs

Dennis

2017

Journal of Natural Gas Science and Engineering

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“…According to several field cases such as the Haynesville shale and Eagle Ford shale, more than 10 stages are completed in order to maximize the exposure to formations for the economic production from shale reservoirs Pope et al, 2012;Thompson et al, 2011). Bazan et al (2010) presented one example of the multistage hydraulic fracturing treatment for the Eagle Ford shale. The…”

Section: Completion Design In Shale Reservoirsmentioning

confidence: 99%

Temperature-Prediction Model for a Horizontal Well With Multiple Fractures in a Shale Reservoir

Yoshida

Zhu

Hill

2014

SPE Production &Amp; Operations

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Fracture diagnostics is a key technology for well performance prediction of a horizontal well in a shale reservoir. The combination of multiple fracture diagnostic techniques gives reliable results, and temperature data has potential to provide more reliability on the results. In this work, we show an application of a temperature prediction model for a horizontal well with multiple hydraulic fractures in order to investigate the possibility of evaluating reservoir and hydraulic fracture parameters using temperature data. The model consists of wellbore model and reservoir model. Sensitivity studies were performed on temperature distribution to identify influential parameters out of the reservoir and hydraulic fracture parameters including reservoir porosity, reservoir permeability, fracture half-length, fracture height, fracture permeability, fracture porosity, fracture network parameters, and fracture interference between multiple clusters. In this work, in order to find contributions by a target fracture, temperature change sensitivity is evaluated. Single fracture case reveals that fracture permeability, network fracture parameters and fracture geometries are primary influential parameters on temperature change at the fracture location. And also, multiple fractures case shows that temperature change is augmented with the increase of fracture geometry and is decreased with the increase of fracture permeability. These results show the possibility of using temperature to determine these sensitive parameters, and also the

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“…The selected well completion, stimulation, production history, and production forecasting were discussed by Meyer et al (2010), Bazan et al (2010), and Xu et al (2012). The general properties of the selected well are showed in Table 9.…”

Section: Fracture Spacing and Recovery Factor Optimization For A Typimentioning

confidence: 99%

“…14. Although there was no unique solution for this case, the best history match was obtained for 40 transverse fractures with an effective fracture half-length (x f ) of 157 ft (this is equivalent to the generation of one fracture for each perforation cluster or 100% fracture efficiency for the case of 10 stages), dimensionless conductivity (C fD ) of 297, and reservoir permeability (k) of 12.2 nd. Bazan et al (2010) performed a new history match for nine months of the same well production, as shown in Fig. 15.…”

Section: Fracture Spacing and Recovery Factor Optimization For A Typimentioning

confidence: 99%

Production Forecasting of Hydraulically Fractured Conventional Low-Permeability and Unconventional Reservoirs Linking the More Detailed Fracture and Reservoir Parameters

Sierra

Mayerhofer

Jin

2013

Day 3 Wed, February 06, 2013

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Fracture stimulation and production forecasting are two important processes for conventional low-permeability or unconventional reservoirs. Fracture stimulation of either type of reservoir helps assure commercial production rates or maximize exploitation, while proper production forecasting informs the operator in advance of the potential short-and longterm value of the well and the area.To provide more accurate recovery forecasts for conventional low-permeability or unconventional reservoirs, one must consider the key parameters of the generated hydraulic fracture, including effective fracture length (affected by filtrate cleanup and fracture damage), relative differences in fracture and formation flow capacity (e.g., dimensionless fracture conductivity), proppant distribution, tapered fracture conductivity, and stress dependence of the fracture conductivity. In addition, stress dependence of reservoir permeability and reservoir fluid properties also have a major impact. Non-darcy and multiphase flow effects inside the fracture have been extensively discussed in the literature and will not be discussed in this paper but can be indirectly included when considering the discussion on reduced fracture conductivity.For the horizontal wellbore architecture commonly used to exploit unconventional reservoirs, the knowledge of the optimum number of fractures to maximize the recovery is very important. This paper uses a numerical reservoir simulation study to develop simple correlations that quantify what fracture spacing is necessary to optimize recovery factors in unconventional gas reservoirs and how various hydraulic fracture parameters and non-ideal reservoir behaviors affect the horizontal well completion design.Because the reservoir simulation process can take significant time and effort, and analytical solutions are sometimes very complex, a simple "back of the envelope" methodology to estimate the optimum fracture spacing can be advantageous for everyday use and a starting point for completion optimization. This paper also discusses how deviations from ideal behavior, in terms of fracture and reservoir properties, can affect the well design.

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Improving Production in the Eagle Ford Shale With Fracture Modeling, Increased Fracture Conductivity, and Optimized Stage and Cluster Spacing Along the Horizontal Wellbore

Cited by 58 publications

References 19 publications

Developing synthetic reservoir type curve model for use in evaluating surface facility and gathering pipe network designs

Developing synthetic reservoir type curve model for use in evaluating surface facility and gathering pipe network designs

Temperature-Prediction Model for a Horizontal Well With Multiple Fractures in a Shale Reservoir

Production Forecasting of Hydraulically Fractured Conventional Low-Permeability and Unconventional Reservoirs Linking the More Detailed Fracture and Reservoir Parameters

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