Shale and other unconventional resources are being called the biggest game changer in a generation – and as land and other costs escalate, the industry continues to apply lessons gleaned from the early successes of the Barnett Shale.
One lesson: High-quality 3-D seismic data has emerged as a valuable tool.
Another lesson: Multi-client seismic surveys have allowed operators to share risks and, more importantly, costs of massive surveys.
High-resolution data provides both “offensive” and “defensive” advantages, said AAPG member Richard Newhart, team-lead subsurface and new ventures in Plano, Texas, for Encana, which is involved in underwriting several multi-client programs including the Haynesville with CGGVeritas.
“Defensively, it allowed us to identify, evaluate and avoid geohazard areas or to map subtle structural changes that assisted in our horizontal geo-steering solutions,” he said.
“Offensively, the data was valuable in building inversion volumes allowing us to map and predict such critical components as gas in place, fracture width and fracture containment – all properties that we were able to directly tie back to production quality of various areas,” Newhart said. “It also had a significant impact on allowing us to correctly risk our portfolio of available locations.”
Advanced reservoir characterization, “including seismic inversion and stress analysis, allows us to derive lithological and geomechanical models,” said Jo Firth, with technology and services marketing for CGGVeritas, “which can be used to predict hydraulic fracture behavior and reservoir drainage geometry, and to estimate TOC (total organic content), shale and carbonate content, water saturation and porosity, etc.”
This can help operators avoid unproductive wells and unnecessary hydraulic fracture stages, Firth said, and also help trim risks by identifying drilling hazards (such as faults) and ductile areas that form boundaries to fracture zones.
Newhart observed that since the early Barnett “land grab” days, leases in shale plays have increased from $500 an acre to $5,000 to $15,000.
“Most resource plays have diverse acreage ownership in their early days,” Newhart said. “Funding and annual budget constraints coupled with survey size and complexity would make acquiring this information on a proprietary basis nearly impossible.
“Those lessons were clearly learned by most operators in the Barnett,” he added.
As many of the early U.S. shale leasehold agreements begin to mature, “operators want to evaluate their positions more carefully to analyze where they can develop quickly to produce the fastest in order to maintain their lease,” said Mike Bertness, vice president of U.S. land multi-client and new ventures for CGGVeritas.
Since 2009, CGGVeritas has heavily invested in its North America shale multi-client data library, Bertness said, including the Haynesville, Bakken (United States and Canada), Montney and Marcellus shale plays, plus active participation in Eaglebine, Utica and the Tuscaloosa marine shale.
“In shale oil plays the terrain is one of the biggest hurdles, as many of the reservoirs are located in the Rockies, so access and permitting become more challenging,” Bertness said. “They are still putting a lot of infrastructure in place – such as housing and hotel accommodations to support the influx of people drawn to develop the area – so grabbing land too early is an issue, but waiting too late means you’ve missed an opportunity.
“Knowing which land to produce first,” he said, “is where the 3-D seismic data becomes extremely useful.
“Usually it takes about 12-18 months to permit, survey, drill and record and process the data,” he continued. “Most leases are three to five years and oil and gas companies do not start working on a seismic program until they drill a few wells and see the production so they are at least one to two years into their leases before doing seismic, so they end up drilling many of the first wells blind.”
Detailed seismic also may help companies in a shale play avoid environmental risks associated with drilling and hydraulic fracturing.
When detailed lithological and geomechanical models of the field are calibrated with well log and core measurements, “they can be used to predict the most productive well locations and also the behavior of induced fractures, such as their direction of propagation and where the rock is too ductile for fractures to form.
“Identifying existing faults and fractures when designing a drilling and completion program, allows these to be avoided, mitigating against the risk of activating them,” Firth said.
Microseismic monitoring of the fracture process can allow actual induced fractures to be compared with the predicted ones in real time, according to Firth, which in turn allows faster options.
“In today’s economic and environmental climate it is essential to make every well and frac count,” Firth added.
Geologists’ and the industry’s growing understanding of the reservoirs and advanced technology promises to push the growth of shale production, according to AAPG member David Bat, president of Welling & Co., an international market research firm serving the upstream petroleum industry.
“Short term, operators will continue to focus on oil and liquid rich regions until natural gas prices recover to a more acceptable level,” Bat said. “Long run, both unconventional oil and natural gas will prove to be the single largest ‘game changer’ this generation has experienced in terms of providing the U.S. both energy independence and economic stability.
“As long as operators continue to have access to land and services, and commodity prices remain stable above $60 per barrel of oil and eventually natural gas prices increase to at least $4 per MCF, the markets should exhibit continued stability and strong growth,” Bat said.
“Lessons learned from the United States will most certainly be applied worldwide,” Bat said, “resulting in similar experiences and economic impact.”