Impact of Liquid Loading in Hydraulic Fractures on Well Productivity

Abstract

One of the major challenges in fracturing low permeability gas formations is the loss of well productivity due to fluid entrapment in the matrix or fracture. Field results have indicated that only 15-30% of the frac fluid is recovered at the surface after flow back. Past studies have suggested that this water is trapped in the rock matrix near the fracture face and remains trapped due to the high capillary pressure in the matrix. Significant efforts have been made in the past to understand the impact of liquid blocking in hydraulically fractured conventional gas wells. This study shows that when considering hydraulic fractures in horizontal wells, the fluid may also be trapped within the fracture itself and may impact the cleanup as well as productivity. Under typical gas flow rates in tight / shale gas formations,liquid loading of both the fractures and the matrix is very likely to occur. This paper presents the results of 3D simulations of liquid loading in hydraulic fractures in horizontal wells, including gravity and capillary pressure effects. The impact of drawdown, fracture and reservoir properties on liquid loading and well productivity is presented. Results show that low drawdown, low matrix permeability or low initial gas rates aggravate the liquid loading problem inside the fracture and thereby impact the gas productivity during initial production.

Experimental investigation of shale imbibition capacity and the factors influencing loss of hydraulic fracturing fluids

“…In the U.S. Haynesville shale formation, the flowback rate is even lower than 5 % after fracturing operations (Penny et al 2006). Besides possibly causing a series of environmental problems, the retention of fracturing fluids in shale formations can greatly enhance the water saturation near fracture surfaces and influence two-phase fluid flow, thus further inhibiting the production of shale gas (Sharma and Agrawal 2013). Furthermore, intense interaction between fluid and shale can dramatically change rock properties and impact on the generation of fracture networks during fracturing (Yuan et al 2014).…”

Coupled Thermo-Hydro-Mechanical-Chemical Modeling of Water Leak-Off Process during Hydraulic Fracturing in Shale Gas Reservoirs

“…where α 2 is described by the Kazemi model to represent the shape factor between the natural fracture and matrix [51]; (µ f w − µ m w )/V w,m represents the non-isothermal chemical potential difference (10 −1 MPa), which is only for water phase, described by Equation (10). (4) Heat Flow in the Natural Fracture…”

“…Many researchers suggest that the low flowback ratio is mainly due to the water leaking into the matrix [3][4][5][6][7]. Other researchers consider that water trapped in the fracture network is another main reason for the low flowback ratio [8][9][10]. In particular, the water leak-off can be attributed to five mechanisms, i.e., hydraulic pressure, natural-fracture dilation, capillarity, chemical osmosis and thermal osmosis during the treatment of hydraulic fracturing.…”

Proppant Transport Simulation in Hydraulic Fractures and Fracture Productivity Optimization

“…After a period of shut-in, days or weeks, the stimulated well will be opened for fracturing fluid flow back and production. Part of the fracturing fluid will be retrieved, but most of it is usually trapped in the matrix near the induced fracture and fracture itself due to gravity segregation and capillary force (Agrawal & Sharma, 2013;Clarkson, 2012;Mahadevan, Sharma, & Yortsos, 2007). Trapped fracturing fluid will compromise the well deliverability, especially in the early production period.…”