| Preview |
Abstract
This paper examines issues with forecasting and evaluating production from
unconventional gas reservoirs, such as the Barnett Shale. How can reservoirs be
commercial with matrix permeability measured not in milli-Darcy or even
micro-Darcy (10-3 mD), but as low as 10-100 nano-Darcy (10-6 mD)? The key is
maximizing the reservoir area that is connected to the wellbore by creating a
very large man-made fracture network. But how do we create a fracture network?
The answer is large volume, high rate hydraulic fracture treatments using water
and small-mesh proppant to activate or stimulate the existing natural fractures
or rock fabric. The fractures created are far from the classic planar model;
they are large complex flow networks that typically encompass more than 50
acres where the rock has been broken. For a given matrix permeability and
pressure, gas production will be determined by the number and complexity of
fractures created, their effective conductivity (kfwf), and the ability to
effectively reduce the pressure throughout the fracture network to initiate gas
production. Understanding the relationship between fracture complexity,
fracture conductivity (kfwf), matrix permeability, and gas recovery is a
fundamental challenge of shale-gas development. This paper highlights the
application of reservoir simulation to model production in shale-gas
reservoirs, providing significant insights into these relationships that can
improve stimulation designs, completion practices, and field development
strategies.
Characterizing the relative conductivity of the fracture network and primary
fracture are critical to evaluating stimulation performance. Because of the
uncertainty in matrix permeability and network fracture spacing (i.e.,
complexity), it is difficult to find unique solutions when modeling production
from unconventional gas reservoirs. The paper demonstrates the application of
numerical reservoir simulation and contrasts this approach with advanced
decline curve analyses to illustrate issues associated with conventional
production data analysis techniques when applied to unconventional reservoirs.
The paper examines the effect of conductivity distribution within complex
fracture networks, complexity of the fracture network, and permeability of the
rock matrix on well productivity and gas recovery. It also illustrates the
effect of gas desorption on the production profile and the ultimate gas
recovery from shale reservoirs.
The paper presents selected examples from the Barnett Shale that incorporate
microseismic fracture mapping and production data to illustrate real-world
applications of the production modeling to evaluate well performance in
unconventional gas reservoirs. Currently, most shale gas resources are
developed using horizontal wells, and the reservoir simulations in this paper
focus on horizontal completions. This paper highlights production modeling and
analysis techniques that aid in identifying stimulation and completion
strategies that may significantly improve production rates and ultimate
recovery from unconventional gas reservoirs.
Introduction
The exploitation of unconventional gas reservoirs has become an
ever-increasing component of North American gas supply, and there is increasing
interest in the potential of international shale gas plays. Gas shales are
organic-rich shale formations that serve as the hydrocarbon source rock and as
the reservoir. In addition to the gas stored in the limited pore space of these
rocks, a sizable fraction of the gas in place may be adsorbed on the organic
material. The success of the Barnett Shale has led to the development of other
shale plays in North America, such as the Woodford, Haynesville, Fayetteville,
and Marcellus. The natural gas resource potential for gas shales is estimated
to range from 500 to 1,000 Tcf in the USA (Arthur et al. 2008). Typical shale
gas reservoirs exhibit a net thickness of 50 to 600 ft, porosity of 2 to 8%,
total organic carbon (TOC) of 1 to 14% and are found at depths ranging from
1,000 to 13,000 ft. Although each shale reservoir poses unique challenges, this
paper summarizes examples from the Barnett Shale because the reservoir is
better understood and because the fracture geometry has been evaluated by means
of microseismic mapping. The Barnett Shale is found at depths of 6,500 to 8,500
ft, with 100 to 600 ft of net thickness, 4 to 5% total porosity, 4.5% TOC,
basin size of 5,000 square miles (3.2 million acres), and OGIP of 50 to 200 bcf
per square mile. Typical Barnett well spacing ranges from 60 to 160 acres with
estimated ultimate gas recovery of approximately 1 to 5 bcf per well.
|
