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Introduction

In low permeability gas reservoirs, hydraulic fracturing is often necessary to stimulate gas recovery and provide economic gas flow rates. A hydraulic fracture is created by pumping large volumes of high viscosity fracturing fluid containing a granular propping agent into the formation. The well productivity is improved by creating a highly conductive flow path from the formation to the wellbore. Achieving and maintaining sufficient fracture conductivity is critical to the optimization of gas recovery from hydraulically fractured wells. The purpose of this research is to study how certain factors affect fracture fluid clean-up behavior, well productivity, and ultimate gas recovery from hydraulically fractured wells.

Several studies have been performed to investigate fracturing fluid clean-up behavior and well productivity. A few studies have determined how various parameters affect fracturing fluid clean-up, while other studies have focused on the factors that affect the productivity of hydraulically fractured wells. The previous work defined some of the problems associated with the clean-up behavior and well productivity. We have extended the previous work to identify the reservoir conditions that determine how productivity is affected by clean-up behavior.

The objectives of this paper are:

  1. to investigate the factors that affect fracture fluid distribution Around a fracture;

  2. to determine which factors most affect fluid clean-up behavior after a fracture treatment;

  3. to quantify the factors that affect well productivity after a hydraulic fracture treatment; and

  4. to provide productivity after a hydraulic fracture treatment; and

  5. to provide recommendations concerning how to produce a well after a hydraulic fracture treatment to optimize gas recovery.

This research was performed as part of the Tight Gas Sands Research Program performed as part of the Tight Gas Sands Research Program sponsored by the Gas Research Institute (GRI) in Chicago, Illinois.

We have used numerical models to simulate fracture fluid invasion and clean-up, as well as long-term productivity. Simulated fracture treatment volumes, injection rates, and pumping times are representative of actual fracture treatments. The model also simulates typical procedures used to shut-in the well after the stimulation treatment and to produce the well after the fracture closes.

The success of a hydraulic fracture treatment is dependent not only on the treatment design, but also on the procedures used to flow back (or clean-up) the fracturing fluids after the treatment. During the hydraulic fracture treatment, a large volume of fracturing fluid is pumped into the formation at high rates. The fracturing fluid is normally a high viscosity, water-based, proppant-ladened polymer gel. By pumping into the formation, the pressure in the wellbore is increased above the least principle stress of the rock causing the rock to split or fracture. As pumping continues, the fracture propagates, and some fracturing fluid leaks-off along the fracture face into the formation. The open fracture is supported by the fluid pressure from the injected fluid and continues to grow until pumping is stopped. The fracture length propagated during the fracture treatment is referred to as the "created" fracture length. The saturation distribution in the invaded zone around the fracture and the factors that control the saturation distribution have been modeled in this research.

After the hydraulic fracture treatment, the well is often shut-in to allow the fracture to close and trap the proppant before flowback of the fracture fluid begins. The high temperature of the surrounding formation heats the fracture fluid causing the gelling agents to "break". The remaining lower viscosity fluid continues to imbibe into the formation. The pressure in the fracture decreases and the fracture closes as leakoff continues. The fracture continues to close until the proppant supports the walls of the fracture. The propping agent keeps the fracture open and maintains fracture conductivity as the well is produced. The fracture length that is supported by the proppant is referred to as the "propped" fracture length. Once the proppant is referred to as the "propped" fracture length. Once the fracture closes. flow is reversed to produce back the fracturing fluid and clean-up the fracture. As flow to the surface continues, the pressure in the fracture is decreased. The amount of fracturing fluid pressure in the fracture is decreased. The amount of fracturing fluid actually produced back, as well as the gas productivity of a hydraulically fractured well, is affected by the fracture conductivity, formation permeability, and damage in and around the fracture.

The fracturing fluid recovery and productivity of a hydraulically fractured gas well are also affected by the operating procedures that are applied after a fracture treatment. Rowing a well too hard in an attempt to increase the flow rate increases the risk of rapid and excessive closure stresses. Excessive closure stress above the strength of the propping agent causes severe crushing of the proppant and a subsequent reduction of fracture conductivity.

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