Production Forecast, Analysis and Simulation of Eagle Ford Shale Oil Wells.

Al-Otaibi, Basel; Schechter, David S.; Wattenbarger, R.A.

doi:10.2118/172929-ms

Cited by 16 publications

(11 citation statements)

References 7 publications

Supporting

Mentioning

Contrasting

Order By: Relevance

“…The matrix permeability is computed to be 0.051 md, according to Equation (). The average fracture half‐length is then calculated to be 176 ft, which is 2.27% higher than the estimated 172 ft fracture half‐length by Alotaibi et al At the beginning of the boundary‐dominated flow, EFS well #6 had an oil production rate of approximately 1,236 stb. Solving Equations () and () simultaneously gives a fracture conductivity of 23 md‐ft.…”

Section: Resultsmentioning

confidence: 67%

“…The performance of the proposed method was verified using data from the Eagle Ford Shale (EFS) well #6 estimated by Alotaibi et al The initial formation pressure is 8,000 psi; the flow pressure is 2000 psi; the oil viscosity is 0.4 cp; the porosity is 0.09; the total compressibility is 1.14 × 10 ‐5 /psi; the oil formation factor is 1.4 rb/stb; the number of fractures is 12; the fracture spacing is 402 ft; the slope of the square root of time is 0.000136; and the time at the end of the half‐slope is about 40 days. The results are listed in Table .…”

Section: Resultsmentioning

confidence: 85%

“…The product of well drainage area and the square root of permeability can be calculated from the slope of the square root of time plot,

\sqrt{k_{m}} A_{cm} = \frac{125.1 μ_{normalo} B_{normalo}}{\sqrt{ϕ μ_{normalo} c_{normalt}} (p_{i} - p_{w})} \frac{1}{m}

where A cm is the well drainage area in ft, B o the oil formation factor in rb/stb, p i is the initial formation pressure in psi, and p w is the bottom‐hole flowing pressure in psi.…”

Section: Methodsmentioning

confidence: 99%

“…During the linear flow period, the square root of time plot follows a straight line on a Cartesian coordinate system. The slope of this line can be used to calculate the product of well drainage (or fracture half‐length) and the square root of permeability …”

Section: Introductionmentioning

confidence: 99%

“…The slope of this line can be used to calculate the product of well drainage (or fracture half-length) and the square root of permeability. 17,18 Estimates of fracture conductivity have not been well studied in the past. The short-term fracture conductivity is usually estimated by pressure transient analysis of fracture linear flow or bilinear flow.…”

Section: Introductionmentioning

confidence: 99%

See 4 more Smart Citations

Statistical analyses of reservoir and fracturing parameters for a multifractured shale oil reservoir in Mississippi

Yang

Guo

2019

Energy Science & Engineering

View full text Add to dashboard Cite

The use of multifractured horizontal wells has improved the efficiency of hydrocarbon extraction from shale gas and oil plays. It is highly desirable to estimate the characteristics of the reservoir and well fracturing through production data analysis. Production rate transient data from 16 wells in the Mississippi sections were analyzed to estimate local reservoir permeability and hydraulic fracture parameters. Key factors affecting well productivity have been identified for optimizing future well completion. Based on the theory of distance of investigation during transient linear flow, the reservoir matrix permeability of TMS was estimated to be between 53 nd and 210 nd, averaging at 116 nd. The matrix permeability follows the lognormal distribution and is considered homogeneous according to the coefficient of variation. The fracture half‐length was estimated using the matrix permeability data from the rate transient analysis. The fracture half‐length was found to have a mean value of 234 ft with a standard deviation of 66 ft in a normal distribution. The fracture conductivity was back‐calculated by matching pseudosteady production rate data to Guo et al's (SPE Reserve Eval Eng.12, 2009, 879) productivity model for boundary‐dominated flow. The fracture conductivity was estimated to range from 0.4 md‐ft to 3.2 md‐ft, averaging at 1.4 md‐ft. Based on Guo et al's (SPE Reserve Eval Eng.12, 2009, 879) well productivity model applied to TMS condition, well productivity can be improved significantly by increasing fracture length and conductivity. Future TMS wells should be completed with conductivity values of greater than 10 md‐ft.

show abstract

Section: Resultsmentioning

confidence: 67%

Section: Resultsmentioning

confidence: 85%

“…The product of well drainage area and the square root of permeability can be calculated from the slope of the square root of time plot,

\sqrt{k_{m}} A_{cm} = \frac{125.1 μ_{normalo} B_{normalo}}{\sqrt{ϕ μ_{normalo} c_{normalt}} (p_{i} - p_{w})} \frac{1}{m}

where A cm is the well drainage area in ft, B o the oil formation factor in rb/stb, p i is the initial formation pressure in psi, and p w is the bottom‐hole flowing pressure in psi.…”