(Tech Connections Column, January 2008, American Oil and Gas Reporter)

There is no denying industry’s strong interest in fractured reservoirs, relevant to both conventional and unconventional resources. This column highlights insights presented during a PTTC workshop in Louisiana and a tight gas-sand application, and points readers toward some additional fractured reservoir resources.

No discussion of fractured reservoirs would be complete without including bore hole imaging. In the Louisiana workshop, Dan Buller of Halliburton Energy Services/Numar illustrated through examples how one could gain insights about secondary porosity, structural geology, mineralization, hydrocarbon entry, and sedimentary structure.

It is important to distinguish between natural and man-made features. Drilling-induced fractures typically are the highest-angle features (75-85 degrees) seen intersecting the well bore. There are imaging tools for both water-based and oil-based systems. One can use sonic shear anisotropy techniques to detect fractures, but in all cases, bore hole imaging is the preferred method.

In fractured reservoirs, mapping hydraulic fracturing has become extremely useful. It can provide answers about fracture orientation, fracture length and height. Those planning fracture stimulation in horizontal wells face several issues. To optimize well bore trajectory and reservoir drainage, one must know about the fracture geometry. There are questions to be answered about well bore trajectory, well bore coverage, interval coverage, diversion and staging considerations, and then there is execution of the fracturing operation itself. Mapping helps define many of these factors.

During the workshop, Steve Wolhart of Pinnacle Technologies Inc. noted that his company had mapped more than 200 Barnett Shale wells. Most early (2001-03) work was in the core area with thicker sections, more gas and good frac barriers. Work then moved to Tier 1 and 2 areas where the Barnett is thinner and there are no fracture barriers. Most effort today is directed toward mapping horizontal wells.

Results indicate that it is stimulated reservoir volume (SRV), not fracture half-length, that is most important. Drainage area will largely be confined to the stimulated network area. Fracture spacing density is very important. Increasing fracture conductivity can provide significant benefits for a large network structure. In attempts to achieve higher SRVs, operators are drilling longer laterals, performing larger jobs, incorporating more stages and perforations, performing refracs, etc. One must balance creating a dense fracture network with overall network size.

It is not only in new resource plays where understanding fractures and their interplay with stimulation reaps rewards. A Society of Petroleum Engineers paper (109948) outlines the history of and technology evolution in the Cleveland tight gassand play. Early development of the Cleveland was with hydraulically fractured vertical wells. Fracturing techniques were refined over the years.

The latest round of vertical development in the mid 1990s was designed to create 175-200 feet of propped fracture length. Analyzing performance of the most recent vertical wells reveals average estimated ultimate recoveries were only in the range of 700 million cubic feet, with initial rates of about 400 Mcf a day. The initial horizontal well was drilled in 1997, but it was not until 2003 that horizontal drilling took off and subsequently became the norm.

Early horizontal well design was a cased and perforated horizontal section 1,500-1,600 feet long with four sets of perforations spaced 400-500 feet apart. Ball sealers were used as a diversion technique between stages. Performance varied widely. Subsequent microseismic surveys indicated that the ball sealers were not a reliable diversion technique.

Completions now have evolved to employing an open-hole multiple packer (OHMP) system. While rarely observed in cores, open-hole image logs revealed they were more common, oriented roughly east to west. Image logs and core data indicate a link between lithology and the presence of natural fractures.

Several microseismic surveys during hydraulic fracturing were made. Taken together, the data indicate that hydraulic fractures tend to initiate in relatively clean sands, which should be considered in placing fracture ports or perforations. This could explain why the OHMP completion design works better.

In early January, PTTC’s Eastern Region was to hold a workshop on the role of fractures in the Devonian Black Shale gas play. Contact Doug Patchen (304-293-2867, ext. 5443) for information. There are additional PTTC workshops scheduled in February in Illinois and Houston on fractured reservoirs. Check PTTC’s calendar at www.pttc.org/national_calendar.htm for details.

Certain concepts are timeless. A 1982 work by Ronald Nelson, “Geological Evaluation of Fractured Reservoirs,” is available on DVD through the American Association of Petroleum Geologist’s bookstore (www.aapg.org, product code 956) for a very nominal price.

Interested in the cutting edge? AAPG’s multiday Hedberg Research Conference scheduled next summer in Wyoming is titled, “The Geologic Occurrence and Hydraulic Significance of Fractures in Reservoirs.” Check AAPG’s Web site for information (www.aapg.org/education/hedberg/).

Last but not least, AAPG’s free online e-publication Search and Discovery, (www.searchanddiscovery.com) also has some interesting geologic works on fracturing.