Low injected fracturing fluid recovery has been an issue during flowback period that is highly impacted by the fracture closure behavior. Although existing flowback models consider fracture closure volumetrically, they do not represent the true situation of non-uniform fracture closure. In this paper, we proposed a coupled geomechanics and fluid flow model for early-time flowback in shale oil reservoirs. The fluid flow model is coupled with an elastic fracture closure model through finite element methods. In this study, three stages are modeled: fracture propagation, well shut-in and flowback. Cohesive Zone Method (CZM) has been used for modeling fracture propagation. The presented model distinguished the propped part from the unpropped part of the fracture. At the beginning of flowback, the proppants may not be completely compacted in early shut-in time. Thus, permeability evolution during closure is tracked using a smooth permeability transition function. The numerical results have shown that fracture closure during the flowback period is often not uniform. While the uniform fracture closure leads to maximum fracturing fluid recovery, an aggressive pressure drawdown strategy may damage fracture connectivity to the wellbore. An integrated flowback model enables modelling nonuniform fracture closure in a complex fracture network. This study highlights that by choke/pressure drawdown management, operators can influence fluid recovery and even maintain high fracture conductivity. Furthermore, the methodology presented in the paper can also be used for inverse analysis on early flowback data.

In multi-fractured horizontal wells (MFHW), fracture properties such as permeability and fracture half-length significantly deteriorate during early production, which negatively affects gas production from shale reservoirs. Therefore, it is crucial to evaluate the temporal changes in fracture properties based on production data. This paper presents a workflow in which both flowback and long-term production data are used to quantitatively evaluate hydraulic fracture closure and changes in the fracture properties. In addition, we develop a two-phase semi-analytical model based on rate transient analysis (RTA) that assumes boundary dominated flow during the flowback period. The proposed workflow consists of three steps. First, we used the flowback data to calculate fracture properties, such as initial fracture permeability and fracture half-length, by employing the two-phase semi-analytical model. Then, we calculated initial fracture permeability by using a single-phase bilinear flow model as well as the fracture half-length and matrix permeability by using a single-phase linear flow model from the long-term gas production data. These models consider pressure dependency of permeability. Last, we compared the results that are calculated from both flowback and long-term production data to evaluate fracture closure and its effects on fracture permeability. We validated the semi-analytical flowback model and the workflow against numerical simulations. The results show that the developed model is capable of predicting fracture properties and evaluating fracture closure. Furthermore, the proposed workflow provides quantitative insights on the performance of fracture stimulation and is able to closely estimate permeability modulus using flowback and long-term production data instead of conducting laboratory experiments.

Abstract When pumped at sufficient rates and pressures, gaseous nitrogen alone has been pressures, gaseous nitrogen alone has been successfully used as a fracturing fluid in the Ohio Shale Formation of the Devonian shale trend. Enhanced production results have proved that use of nitrogen, even without a propping agent, has outperformed other stimulation systems employed in this lithological area of Ohio and West Virginia. Job design and procedures for nitrogen fracturing are presented in this paper as are production results of five treatments production results of five treatments performed in the Ohio Shale Formation. performed in the Ohio Shale Formation Introduction In Washington County, Ohio, there are as many as 14 different producing zones. Encountered at depths of approximately 2,000 feet to 3,900 feet, the Ohio Shale Formation is considered to be any zone located below the Berea Formation and above the Huntersville Formation. Porosity in the Ohio Shale Formation is low, ranging from 0.1 percent to 4 percent. Overburden pressures percent to 4 percent. Overburden pressures vary from 1,600 psi to 2,700 psi. Also, permeability values range from 0.0001 md to permeability values range from 0.0001 md to 0.01 md which results in low production rates. These low rates of production occur because the low permeability of the shale limits the rate at which reservoir fluids can diffuse through the formation matrix, through natural fractures and on to the wellbore. However, extended production lives are observed as a result. The area also has a low stress ratio factor which implies a high density of natural fractures. This accounts for the large volumes of trapped oil and gas and also contributes to the porosity of the system, thus, allowing the zone to act as a reservoir. Because initial production usually declines rapidly, stimulation is required to increase or maintain rates. The rapid decline of initial production is due to the random distribution of fractures characterized by a lack of communication between fractures in the zone and between fractures and the wellbore. Such low pressure reservoirs also make clean-up operations difficult. Following conventional treatments, most wells in this area load up with fluid while flowing back and then die. Consequently, a swabbing unit is usually required to help recover treating fluids. The failure to completely recover treating fluids is often considered the cause of poor production rates. The problems inherent with conventional fracturing treatments, including lost production, additional costs of swabbing production, additional costs of swabbing operations, and possible formation damage from unrecovered fluids, forced local operators to pursue new ways to treat wells in the Ohio Shale Formation. STIMULATION HISTORY Zones such as the Ohio Shale Formation, which have high shale content and natural fractures, have long been difficult to stimulate. These formations can be characterized as virtually impermeable, low-pressure reservoirs requiring special efforts to enhance recovery of hydrocarbons. The productivity of wells drilled in this interval is dependent on the density and extent of the natural fractures within the shale matrix. The fractures in the reservoir are both the source and the seal for organic carbons. P. 189