Hydraulic fracturing of wells in naturally fractured reservoirs can differ dramatically from fracturing wells in conventional iso- tropic reservoirs. Fluid leakoff is the primary difference. In conventional reservoirs, fluid leakoff is controlled by reservoir matrix and fracture fluid parameters. The fluid leakoff rate in naturally fractured reservoirs is typically excessive and completely dominated by the natural fractures.
Historically, attempts to fracture stimulate wells in naturally fractured reservoirs have been unsuccessful due to high leakoff rates and gel damage. The typical approach is to attempt to control the leakoff with larger pad volumes and solid fluid loss additives. This approach is not universally effective and can do more harm than good.
This paper presents several field examples of a fracture stimulation program performed on the naturally fractured Devonian carbonate of West Texas. Qualitative pressure decline analysis and net treating pressure interpretation techniques were utilized to evaluate the existence of natural fractures in the Devonian Formation. Quantitative techniques were utilized to assess the importance of the natural fractures to the fracturing process. This paper demonstrates that bottom hole pressure monitoring of fracture stimulations has benefits over conducting minifrac treatments in naturally fractured reservoirs. Finally, the results of this evaluation were used to redesign fracture treatments to ensure maximum productivity and minimize costs.
Hydraulic fracturing in naturally fractured or fissured reservoirs can differ greatly from hydraulic fracturing in conventional reservoirs. In conventional reservoirs, fluid leakoff is dependent on matrix permeability, fluid viscosity, and reservoir fluid compressibility. Fluid leakoff in naturally fractured reservoirs is dominated by the natural fractures themselves. This fissure-dominated leakoff mechanism varies with stress or net pressure and, as a result, is less predictable. Because of this, treatments in naturally fractured reservoirs often terminate prematurely. As a result, it is critical that the existence of natural fractures be known prior to the hydraulic fracture treatment so that methods are employed to eliminate or at least minimize excessive leakoff. These methods have included the use of 100 mesh sand and/or silica flour and excessive fluid volumes and rates (i.e., live with it). Each of these techniques has had limited success.
Nolte and Smith showed how natural fractures affected net treating pressures and established that treating pressures in excess of the critical pressure generally resulted in premature screenouts. In addition, they showed a qualitative method of identifying natural fractures by evaluating a log-log plot of net treating pressure versus pump time. Their work showed net pressure tends to flatten when excessive leakoff to the natural fractures occurs (i.e., the critical pressure is achieved). This qualitative interpretation technique has become an industry standard.
NoIte presented diagnostic techniques for analyzing fracture behavior from pressure decline analysis. He showed diagnostic techniques for interpreting conventional and abnormal leakoff phenomena and qualitative techniques for identifying the existence of natural fractures. He further showed that the pressure decline function, G, for pressure-dependent leakoff is convex in character, and can be used as a diagnostic test of pressure-dependent leakoff.
Numerous authors have presented results which showed that hydraulic fracturing in naturally fractured reservoirs can adversely impact well erformance due to gel damage and/or stress sensitivity. These works highlight the detrimental effects of excessive leakoff in naturally fractured reservoirs.
Mukherjee showed the stress-sensitive nature of the fluid leakoff and proposed methodology to handle fluid leakoff as a function of net treating pressure. Warpinski showed that the fluid leakoff to natural fracture systems can be as much as 50 times greater than matrix leakoff. He further presented the successful application of 100 mesh sand as a fluid loss additive in naturally fractured reservoirs to minimize these detrimental effects, as did Northcutt et al.