Development of reservoir economic indicator for Barnett Shale gas potential evaluation based on the reservoir and hydraulic fracturing parameters

Nguyen-Le, Viet; Shin, Hyundon

doi:10.1016/j.jngse.2019.03.024

“…Even so, the ease with which longstanding, simplistic adsorption theories, such as Langmuir and BET, can be fit to shale adsorption isotherms has led to their widespread incorporation into shale characterization [9], [3], [10], [11] and reservoir modeling. [12]- [14] However, we prove here that despite the fact that the shapes of shale isotherms are often similar to IUPAC isotherms, the underlying physics are generally not the same. By creating controlled pore size distributions with a synthetic nanoporous medium called MCM-41 and comparing the isotherms measured in them to those measured in shale, we show that the broad pore size distribution of shale can alter the appearance of capillary condensation and continuous pore filling such that they manifest much differently from the traditional IUPAC Type IV isotherm.…”

Section: Introductionmentioning

confidence: 59%

Using Capillary Condensation and Evaporation Isotherms to Investigate Confined Fluid Phase Behavior in Shales

Barsotti

¹

,

Lowry

²

,

Piri

³

et al. 2020

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The abundance of nanopores (pores with diameters between 2 and 100 nm) in shale and ultra-tight reservoirs precludes the use of common pressure-volume-temperature (PVT) analyses on reservoir fluids. The small sizes of the pores cause capillary condensation, which is a nanoconfinement-induced gas-to-liquid phase change, that can occur at pressures more than 50% below the corresponding bulk phase change of the fluid due to strong fluid-pore wall interactions. We quantify this phenomenon by measuring propane isotherms both in a synthetic nanoporous medium and a core from a shale gas reservoir. Comparison of our results in the two porous media indicates the occurrence of capillary condensation in shale rock. At the same time, we observe capillary condensation hysteresis for shale, in which the density of the fluid is significantly lighter during desorption than adsorption. This indicates structural changes to the rock matrix caused by the phase behavior of the confined fluid. We use scanning electron microscopy to corroborate our findings. These results have significant implications for determining the PVT properties, porosity, and permeability of shale and ultra-tight formations for use in reservoir modeling and production estimations.

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“…The reservoir dimension was 1463 m (length) × 305 m (width) × 91 m (thickness). The input data for the base reservoir model simulation were average values of available data from the Barnett shale reservoir [23][24][25]. The CMG's GEM simulator [26] was employed to simulate the base reservoir simulation case (reservoir depth = 2057.40 m, reservoir pressure = 22,063 kpa, reservoir temperature = 96.11 • C, matrix porosity = 0.05, matrix permeability = 0.00023 md, and initial gas saturation = 0.7).…”

Section: Numerical Simulation Modelmentioning

confidence: 99%

“…The amount of (monolayer) gas adsorbed in organic-rich shales was defined by the Langmuir equation [27], and has recently been applied in other shale gas researches [28][29][30]. Langmuir isotherm data for the Barnett shale are Langmuir volume of 3.54 scm/ton, Langmuir pressure of 8618 kpa, and rock density of 2.50 g/cm 3 [23][24][25]. Input data for hydraulic fracture model were fracture half-length of 106.68 m, fracture spacing of 121.92 m, and fracture conductivity of 1.52 md-m.…”

Section: Numerical Simulation Modelmentioning

confidence: 99%

Development of Shale Gas Prediction Models for Long-Term Production and Economics Based on Early Production Data in Barnett Reservoir

Nguyen-Le

¹

,

Shin

²

,

Little

³

2020

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This study examined the relationship between the early production data and the long-term performance of shale gas wells, including the estimated ultimate recovery (EUR) and economics. The investigated early production data are peak gas production rate, 3-, 6-, 12-, 18-, and 24-month cumulative gas production (CGP). Based on production data analysis of 485 reservoir simulation datasets, CGP at 12 months (CGP_12m) was selected as a key input parameter to predict a long-term shale gas well’s performance in terms of the EUR and net present value (NPV) for a given well. The developed prediction models were then validated using the field production data from 164 wells which have more than 10 years of production history in Barnett Shale, USA. The validation results showed strong correlations between the predicted data and field data. This suggests that the proposed models can predict the shale gas production and economics reliably in Barnett shale area. Only a short history of production (one year) can be used to estimate the EUR and NPV of various production periods for a gas well. Moreover, the proposed prediction models are consistently applied for young wells with short production histories and lack of reservoir and hydraulic fracturing data.

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“…Some studies proposed prediction models for the shale gas production and net present value (NPV) [5][6][7][8][9]. The prediction models were developed using various analysis techniques and reservoir simulation data.…”

Section: Introductionmentioning

confidence: 99%

“…Kim et al [6] developed the neural network-based proxy model for predicting shale gas production using the reservoir and fracture design parameters. Nguyen-Le and Shin [7] presented a framework for the development of an economic indicator of shale gas projects based on the reservoir parameters, hydraulic fracturing parameters, and gas price scenarios. Furthermore, Nguyen-Le et al [8,9] developed long-term shale gas production models using early production data in the Barnett shale reservoir.…”

Section: Introductionmentioning

confidence: 99%

Development of Production-Forecasting Model Based on the Characteristics of Production Decline Analysis Using the Reservoir and Hydraulic Fracture Parameters in Montney Shale Gas Reservoir, Canada

Shin

¹

,

Nguyen-Le

²

,

Kim

³

et al. 2021

Geofluids

Self Cite

2

0

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This study developed a production-forecasting model to replace the numerical simulation and the decline curve analysis using reservoir and hydraulic fracture data in Montney shale gas reservoir, Canada. A shale-gas production curve can be generated if some of the decline parameters such as a peak rate, a decline rate, and a decline exponent are properly estimated based on reservoir and hydraulic fracturing parameters. The production-forecasting model was developed to estimate five decline parameters of a modified hyperbolic decline by using significant reservoir and hydraulic fracture parameters which are derived through the simulation experiments designed by design of experiments and statistical analysis: (1) initial peak rate ( P hyp ), (2) hyperbolic decline rate ( D hyp ), (3) hyperbolic decline exponent ( b hyp ), (4) transition time ( T transition ), and (5) exponential decline rate ( D exp ). Total eight reservoir and hydraulic fracture parameters were selected as significant parameters on five decline parameters from the results of multivariate analysis of variance among 11 reservoir and hydraulic fracture parameters. The models based on the significant parameters had high predicted R 2 values on the cumulative production. The validation results on the 1-, 5-, 10-, and 30-year cumulative production data obtained by the simulation showed a good agreement: R 2 > 0.89 . The developed production-forecasting model can be also applied for the history matching. The mean absolute percentage error on history matching was 5.28% and 6.23% for the forecasting model and numerical simulator, respectively. Therefore, the results from this study can be applied to substitute numerical simulations for the shale reservoirs which have similar properties with the Montney shale gas reservoir.

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Development of reservoir economic indicator for Barnett Shale gas potential evaluation based on the reservoir and hydraulic fracturing parameters

Cited by 41 publications

References 8 publications

Using Capillary Condensation and Evaporation Isotherms to Investigate Confined Fluid Phase Behavior in Shales

Using Capillary Condensation and Evaporation Isotherms to Investigate Confined Fluid Phase Behavior in Shales

Development of Shale Gas Prediction Models for Long-Term Production and Economics Based on Early Production Data in Barnett Reservoir

Development of Production-Forecasting Model Based on the Characteristics of Production Decline Analysis Using the Reservoir and Hydraulic Fracture Parameters in Montney Shale Gas Reservoir, Canada

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