First Break - Volume 27, Issue 4, 2009

As gas demand rises around the world and operators turn to tight gas reservoirs for new supplies, the need to optimize the capacity and recovery potential from low-permeability reservoirs has risen. An economically efficient integrated process developed in North American projects enables the data and activities of multiple domains to be integrated for single-well completion optimization field modelling level. The approach constitutes a paradigm shift from how the industry operates and develops fields outside North America today, but as we will show, it has been equally successful in a Middle East tight gas development.

Development of tight gas in continental North America has a long history. Some of the early attempts at stimulating and producing economically from microdarcy formations date back to the 1970s (Holditch et al., 1971, Fast et al., 1977, Wyman, 1980). The US price incentives in the Natural Gas Policy Act of 1978 spurred technology development, most notably massive hydraulic fracturing (MHF). Since then improvements in fracturing technology have continued unabated. Horizontal wells and more recently multi-stage hydraulically fractured horizontal wells represent the state of the art. Continued improvements in exploration/imaging tools, and advances in reservoir engineering interpretation techniques have helped identify what is actually occurring in the field. All of these factors have made tight gas a significant part of the current North American gas production. Kuuskraa (2006) estimated that unconventional gas (including tight gas, coalbed methane and shale gas) accounted for 40% of US natural gas production in 2004, and is rising every year.

What role can geophysics play in tight gas exploration and production? The answer may be a surprise. We have been able to use multi-component seismology at Rulison Field, Colorado, to not only find ‘sweet spots’ but to monitor pressure depletion during development of this resource. By monitoring pressure depletion, we can identify drainage and connectivity and do a better job of ‘sweeping’ the reservoir while identifying bypass pay.

This paper summarizes recent reservoir characterization and simulation studies performed in the Jonah Field, one of the most prolific natural gas fields in the Rocky Mountain region of the United States. The goal of the studies was to integrate geology, petrophysics, 3D seismic, and engineering data into 3D geologic and engineering models to evaluate infill well development in different regions of the field. This article shows how variations in channel development and thickness have a direct impact on gas recovery and optimal well spacing for different areas of the field. We also show that these channels can be mapped with the help of attributes inverted from pre-stack seismic data.

The Mississippian Barnett Shale of the Fort Worth Basin (Texas, USA) is potentially the largest gas field in North America. As with most tight gas fields, successful Barnett well creation requires accurate well path placement in the gas zone: with judicious alignment of the well path relative to existing fractures and current stress orientations, followed by effective hydraulic fracturing. Previous work has established a current stress orientation of approximately 50−60° east of north.

Mohammed Y. Ali, Karl A. Berteussen, James Small, Braham Barkat and Okky Pahlevi present a low frequency passive seismic investigation over an onshore carbonate oilfield in Abu Dhabi to determine the spectral content, apparent velocities, and azimuths of the wavefronts in the microseism and microtremor bands.

Karl A. Berteussen offers this personal essay on how the size of an oil field can affect the economic decision-making process based on the available geophysical data. The implications could be significant for new technologies like EM and for geographic regions such as the Middle East.

The Heidrun Field, offshore mid-Norway is compartmentalized by a large number of faults and stratigraphic barriers, making prediction of flow and contact movements difficult, especially in the complex Åre Formation. In 2006, a time-lapse seismic survey was conducted over the north flank of the field giving, for the first time, the opportunity to monitor fluid movements in the Åre Formation. Using these time-lapse data, evidence of communication across faults and across the stratigraphy has been obtained and we discuss two examples for the Åre Formation. The observations in the Åre Formation have increased the understanding of flow movements and given valuable input for identifying new drainage points. In addition, the results have led to a revision of the field’s injection strategy. Integrated work by a team of geophysicists, reservoir engineers, and geologists has resulted in a total of 22 flooding maps, including 13 new maps for the Lower Tilje Formation and the Åre Formation.