Risk Analysis in the Process of Hydraulic Fracturing

Introduction

While hydraulic fracturing is a well-developed technology that has been used for more than 60 years in petroleum engineering, its wide-spread use for coal-bed natural gas and shale gas development has raised questions about the appropriate regulatory approach to ensure that groundwater resources and surface water are protected (Arthur, 2011). Millions of fracs have been pumped (SPE - Society of Petroleum Engineers estimate 2.5 million fracs world-wide). The technical literature on hydraulic fracturing is extensive, addressing nearly every aspect of oil and gas development, with over 550 papers in shale fracturing. The shale papers in the past several years alone are from more over 70 universities, over a dozen state, federal and international agencies and more then a hundred energy and service companies (King, 2010; Arthur, 2009).

However, recent exposure of the general public to this technology, particularly as practiced with large volume of water, has resulted in considerable fear and misunderstanding of what is occurring downhole. Fortunately, the industry has been studied the problem of fracture height growth for several decades and has been monitoring fractures with tiltmeters for two decades and with microseismics for over one decade. All data of investigation has shown that hydraulic fracturing in typical reservoirs is not threat to fracture into and contaminate or otherwise disturb groundwater (Warpinski, 2011). In engineering terms, fracturing concerns a precise stimulation activity, limited to the fluid action in initiating and extending cracks in the rock; while, for many concerned citizens, bloggers and environmentalists, fracturing has come to represent nearly every phase of the well development cycle from drilling to production.

First, scale drawings of the distance from the surface and near-surface fresh water supplies (nearly all fresh water formations are within the first 300 meters from the surface) are needed to show the physical distance between the surface and the completion interval of interest (pay zone).

Fracture height, predicted by computer models and confirmed by microseismics monitoring during fracturing, post-frac tracer flows, temperature logs and even by mine-back experiments (Warpinski, 1985), show most vertical effective fracture growth at 100 meters or less. Fracture height growth in most formations is known to be effectively limited by barriers and fluid leakoff (loss of fluid to the rock). Fracture heights limited by these physical and active barriers will simply not reach into fresh water sands.

Although the fracturing process is more than thousand meters away from the water table, methane is showing up in residential water wells, but this contamination in water wells is caused by other natural and manmade causes. Part of the reason is the natural occurrence with biogenic methane forming from shallow decay of organic materials and natural seeps of thermogenic methane (gas formed deep in the earth) that have been coming to the surface for millions of years, particularly in regions with shale and coal outcrops or shallow formations that share the water table with fresh water wells.

However, part of the increasing methane content in water well may be coming from near-by improperly constructed gas or oil well. These older wells predate the invention of hydraulic fracturing and most predate any significant well construction regulations. Deeper formations are at higher pressures and exposure of these zones without sufficient cementing isolation will allow gas seepage that will build up a higher pressure that was customary at shallower depths. This type of methane leak is usually low volume and is made possible by poor or incomplete cementing practices. The incident can be noticed soon after drilling and can start before the well is fractured.