Shale Gas Production Decline Trend Comparison Over Time and Basins Revisited

Baihly, Jason; Malpani, Raj; Altman, Raphael; Lindsay, Garrett; Clayton, Richard

doi:10.15530/urtec-2015-2172464

Cited by 16 publications

(27 citation statements)

References 10 publications

Supporting

Mentioning

Contrasting

Order By: Relevance

“…(Baihly et al, 2010(Baihly et al, , 2015 also observed the same results in initial gas production rate from the Barnett shale when compared to other major US shale gas plays like Haynesville, Marcellus, Eagleford, Woodford and Fayetteville. Figure 3 shows the variability in performance among the different shale plays (Baihly et al, 2015). Stephens non-core counties (Table 1).…”

Section: Introductionsupporting

confidence: 62%

“…The initial gas production rate in the Barnett shale was also found to be lower compared to other major US shale gas plays like the Eagleford, Marcellus and Haynesville shale (Rezaee, 2015). (Baihly et al, 2010(Baihly et al, , 2015 also observed the same results in initial gas production rate from the Barnett shale when compared to other major US shale gas plays like Haynesville, Marcellus, Eagleford, Woodford and Fayetteville. Figure 3 shows the variability in performance among the different shale plays (Baihly et al, 2015).…”

Section: Introductionmentioning

confidence: 53%

See 1 more Smart Citation

Shale gas production decline trend over time in the Barnett Shale

Kenomore

Hassan

Malakooti

et al. 2018

Journal of Petroleum Science and Engineering

View full text Add to dashboard Cite

Natural gas produced from shale formations in the United States over the past decade have altered the oil and gas industry remarkably. The Barnett shale was at the forefront of the shale gas revolution in the United States and was considered to be the highest producing natural gas field in the United States until 2012, yielding the top producer spot to the Marcellus shale. Due to the uncertainty regarding the accurate determination of Estimated Ultimate Recoverable (EUR) in shale gas reservoirs, this paper aims to assess EUR values for the Barnett shale using empirical decline curve methods like the Arp's hyperbolic, Modified Arp's hyperbolic and Doung's method. In addition, we investigated the economic viability of wells over time in the Barnett under various probabilities of success. Throughout this paper, reference is made to two key publications where a similar work was carried out for various shale plays in the United States, including the Barnett shale -though only the Arp's hyperbolic decline was employed.The dataset in this paper consisted of more horizontal wells from covering more counties within the Barnett shale compared to other similar studies. We conclude that either the Arp's hyperbolic or Doung's method can be used to forecast EUR in the Barnett shale as only marginal differences were observed. This is on the basis that production history exceeds 10 months (a maximum of 80 months production history was used). We also obtained reliable and conservative estimates of EUR compared to previous studies.

show abstract

Section: Introductionsupporting

confidence: 62%

Section: Introductionmentioning

confidence: 53%

Shale gas production decline trend over time in the Barnett Shale

Kenomore

Hassan

Malakooti

et al. 2018

Journal of Petroleum Science and Engineering

View full text Add to dashboard Cite

show abstract

“…An approximation of 1.25 trillion cubic meters of gas can be technically recovered from the Barnett reservoir [19][20][21]. Compared to the other major shale gas plays in the USA, the Barnett shale has the lowest initial gas production rate and the lowest decline rate after 5 years of production [14,15]. The typical reservoir depth is 1980-2590 m, and the reservoir thickness is 30-180 m [22].…”

Section: Barnett Shalementioning

confidence: 99%

“…The performance of a well is related strongly to the production rate, particularly for a shale gas well whose production rate is featured by a high initial decline rate after peak production [14,15]. Therefore, early production data can be used as a key parameter for predicting the performance of a shale gas well at the end of life.…”

Section: Introductionmentioning

confidence: 99%

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

2020

View full text Add to dashboard Cite

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.

show abstract

“…However, despite further improvements to geomechanical models, recovery from gas shales is still low, and the decline rate of unconventional reservoirs is still concerning (Baihly et al, 2015). One reason for this unfavorable situation is the uncertainty in modeling the propagation of the fracture tip and aperture, within shales.…”

Section: Introductionmentioning

confidence: 99%

The Assessment of Organic Matter Young's Modulus Distribution With Depositional Environment and Maturity

et al. 2020

View full text Add to dashboard Cite

Quantification of risk to seal integrity in CCS, or gas extraction from hydraulic fracturing, is directly affected by the accessibility of organic pores within organic rich mudrocks. Knowledge of the host organic matter's mechanical properties, which are influenced by depositional environment and thermal maturity, are required to reduce operational risk. In this study we address the effect of both depositional environment and maturity on organic matter Young's modulus by means of Atomic Force Microscopy Quantitative Imaging TM , which is a nondestructive technique capable of nanomechanical measurements. Shales from varying marine depositional environments covering kerogen Types II (Barnett), IIS (Tarfaya), and II/III (Eagle Ford/ Bowland) are analyzed to capture variance in organic matter. The findings show organic matter has a Young's modulus ranging between 0.1 and 24 GPa. These marine shales have a bimodal distribution of Young's modulus to some degree, with peaks at between 3-10 and 19-24 GPa. These shales exhibit a trend with maturity, whereby Young's modulus values of <10 GPa are dominant in immature Tarfaya shale, becoming similar to the proportion of values above 15 GPa within the oil window, before the stiffer values dominate into the gas window. These peaks most likely represent soft heterogeneous aliphatic rich kerogen and stiff ordered aromatic rich kerogen, evidenced by the increase in the stiffer component with maturity and correlated with 13 C NMR spectrocopy. These findings enable increased realism in microscale geomechanical fracture tip propagation models and may allow direct comparison between Young's modulus and Rock-Eval parameters. Plain Language Summary Gas recovery from hydraulic fracturing and validating the top-seal integrity for carbon capture and storage require knowledge of key mechanical properties of the associate mudrock. One key property is elasticity (Young's modulus), which is relatively well constrained for each component of a shale, except for the organic matter. This has historically been due to the difficulties in analyzing elasticity at the resolution of organic matter particles, which can be <1 micron in diameter. Here we use a new technique to measure elasticity at a spatial resolution of between 10 and 50 nm. Organic matter elasticity measurements have been undertaken on a range of shales from marine and lacustrine depositional environments and a range of thermal maturities. The marine-derived organic matter exhibits a bimodal distribution with a peak at around 3-10 and 19-22 gigapascals (GPa). When comparing the shale samples with maturity, a clear bimodal trend is observed within the marine-derived organic matter, which becomes increasingly dominated by a stiffer (higher Young's modulus) peak with maturity.

show abstract

Shale Gas Production Decline Trend Comparison Over Time and Basins Revisited

Cited by 16 publications

References 10 publications

Shale gas production decline trend over time in the Barnett Shale

Shale gas production decline trend over time in the Barnett Shale

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

The Assessment of Organic Matter Young's Modulus Distribution With Depositional Environment and Maturity

Contact Info

Product

Resources

About