New Advances in Shale Reservoir Analysis Using Flowback Data

Abstract

Shale reservoirs with multistage hydraulic fractures are commonly characterized by analyzing long-term gas production data, but flowback data is usually not included in the analysis. However, this work shows there can be benefits to including flowback data in well analysis. The flowback period is dominated by water flow. Field data indicate that only 15-30% of the frac water is recovered after the flowback. Past publications have suggested that the lost water is trapped in the natural fracture or imbibed into the rock matrix near the fracture face. In this paper, lost water scenarios are tested and examples are presented for including flowback and production data in the analysis of shale gas wells. A gas-water model was constructed for simulating the flowback and long-term production periods. Various physical assumptions were investigated for the saturations and properties in the fracture/matrix system that exists after hydraulic fracturing. The results of these simulations were compared with data from actual wells. The result of these comparisons led to certain conclusions and procedures that describe possible well/reservoir conditions after hydraulic fracturing and during production. In this work, the challenge of simulating a natural fracture with trapped water without imbibition is solved using a new hybrid relative permeability jail. This concept was tested for the period of flowback, shut-in and production. Natural fracture spacing could be a possible explanation of the lost water. In addition, this paper shows the benefits of combining flowback and long-term water production data in the analysis of shale gas wells. In some cases the time shift on diagnostic plots changes the apparent flow regime identification of the early gas production data. This leads to different models of the fracture/matrix system. The presented work encourages the engineer to collect flowback data in order to include it in the long-term production analysis.

Analysis of Chemical and Toxicological Properties of Fluids for Shale Hydraulic Fracturing and Flowback Water

“…After cracking a well, the fluid is removed from the drillbore as well as from the cracks and gaps in the surrounding rock. As has been proved in American research, the amount of the fluid obtained in shale gas fracturing is lower than in the case of a tight oilfield: 40-60% for a vertical well and 10-30% for a horizontal well [11,12].…”

“…Total Petroleum Hydrocarbon (TPH) was analyzed by gas chromatography (GC) [11]. Chloride analyses were done with an argentometric method.…”

Numerical investigation of fluid-loss mechanisms during hydraulic fracturing flow-back operations in tight reservoirs

“…Firoozabadi and Hauge (1990) have demonstrated that fracture capillary pressure is greater than zero, depending on the roughness, aperture, and pore structure. This is inconsistent with Cheng (2012), in which zero secondary fracture capillary pressure was used, and Wattenbarger and Alkouh (2013), in which the secondary fracture capillary pressure was the same as the matrix capillary pressure. In addition, wettability influence has often been ignored: assuming neural wettability and identical relative permeability functions in both matrix and secondary fractures (Wattenbarger and Alkouh, 2013).…”

“…However, less than 50% of fracturing fluids are typically recovered (McClure, 2014;Cheng, 2012;Wattenbarger and Alkouh, 2013). Three fluid-loss mechanisms have been reported in the literature (Pagels et al, 2012;Wattenbarger and Alkouh, 2013).…”

“…A third approach, such as the triple-porosity model, can be considered as a combination of the first and second approaches, in which flow within the connected fracture network is modeled explicitly, while matrix contribution is modeled through a set of transfer functions. To explicitly compute saturation variation and water retention in both matrix and fracture systems, only the single-porosity approach has been adopted successfully (Cheng, 2012;Wattenbarger and Alkouh, 2013). Cheng (2012) built a single-porosity model incorporating eight stages of hydraulic fractures, with symmetrical and fully-connected secondary fractures.…”