BUS606: Operations and Supply Chain Management

In this study, two multi-fractured horizontal wells drilled in a gas window of a shale gas basin were investigated. The two wells are producing the same fluids, and they are located close to each other.

The uncertainty of a range of parameters, such as fracture height (h_f), fracture half-length (x_f), number of fractures, reservoir permeability, reservoir initial pressure, and fluid properties, was investigated. In multi-fractured horizontal wells drilled in a shale gas reservoir, the unknown parameters are more than the known parameters. Fracture height is the most uncertain parameter among them because an accurate or direct method to determine the fracture height in horizontal wells is not available. The fracture height in vertical wells can be determined using temperature and acoustic, pulsed neutron, or radioactive tracer surveys in a straightforward manner. Even though the fracture height in multi-fractured horizontal wells can be determined through well testing and simulation, a direct method such as in the case of vertical wells is not available. To reduce the uncertainty in the determination of the fracture height, it is considered as equal to the formation thickness.

The fracture half-length can be determined using gas well production data analysis. Long-term production data are required to determine accurate values of the fracture half-length. Several techniques and methods, such as production analysis, can be used to determine the fracture half-length. Advisory systems built based on field experience in tight reservoirs to predict the fracture half-length have produced results that match well with those obtained from production data analysis. Micro-seismic monitoring can be used to determine the fracture half-length. Production logging and production data can be integrated to evaluate the post-fracturing operation success. Production history matching using proxy models has been used to characterize the fractures and production from shale gas reservoirs.

Regarding the permeability of a reservoir, two permeability values are of interest. They are the non-stimulated rock permeability or the outer permeability, and the stimulated rock permeability or the inner permeability. The maximal inner permeability is estimated from the linear flow behavior using Eq. (1):

$\left(\frac{p_{i}-p_{\mathrm{wf}}}{q}\right)=m_{L} \sqrt{t}+b_{L} S_{f}$                  (1)

where p_i is the initial reservoir pressure, p_wf is the bottom-hole flowing pressure, q is the gas flow rate, m_L is the slope of the linear flow region, t is the time, b_L is the intercept, and S_f is the fracture face skin. The outer permeability of the stimulated reservoir volume (SRV) can be estimated using the diagnostic fracture injection test (DFIT).

Accurate initial reservoir pressure can be determined using post-closure analysis. If the direct measurement of the pressure is not available, an estimation can be used from nearby wells. The upper limit of the initial pressure should not exceed the fracture gradient pressure, and lower limit can be considered as that estimated from the pressure build-up test.

For a near-critical fluid such as condensate gas, a full PVT study on an early bottom-hole sample is highly recommended. If it is not available, the equation of state (EOS) calibrated using a recombined wellhead sample can be used.

In this paper, two wells drilled in a shale gas reservoir were analyzed. The two wells have produced for several months at a high gas/oil ratio. The reservoir temperature is 270 °F, the flowing bottom-hole pressure was set to be a minimum of 100 psi, the reservoir length is 4812 ft, and the reservoir width is 1300 ft. The reservoir height is 93 ft, and the reservoir rock bulk density is 2.5 g/cm³.