These dense rocks have characteristics that can vary not only from region to region but also within specific plays.
For example, even though natural fractures ordinarily are the principle conduit for production flow in shales, all fractures are not created equal. They vary in numerous ways, including intensity, distribution, size and porosity/occlusion patterns.
Actually, there’s no guarantee they even will be present.
The folks at Petrohawk, who discovered the still-new Eagle Ford shale gas play in south Texas (see January EXPLORER), haven’t yet seen any natural fracturing in the Eagle Ford core data after drilling a number of wells, according to AAPG member Dick Stoneburner, executive vice president and COO at the company.
The proliferation of domestic shale gas plays has come about through advanced technology, such as horizontal drilling techniques and increasingly efficient frac stimulation treatments, leading to more cost-effective production.
Economically exploiting these rocks, however, is not necessarily a slam-dunk.
An example is the New Albany Shale in the Illinois Basin, which is the focus of an ongoing R&D project under the aegis of the Gas Technology Institute. The field-based industry cooperative project is funded by the Research Partnership to Secure Energy for America (RPSEA).
The New Albany can vary significantly in different parts of the basin. The goal of the GTI research team is to develop techniques and methods to increase productivity of New Albany shale gas wells to a level where the otherwise non-commercial gas resource may become commercially viable, according to Kent Perry, executive director of GTI’s E&P research-supply sector.
Iraj Salehi, senior institute scientist at GTI, is at the helm of the project.
“We’re integrating all the necessary aspects of developing a shale resource into this project,” Perry said. “The New Albany Shale will require careful consideration of well drilling geometries, accurate formation characterization and completion practices to ensure optimum gas recovery.”
Production in the region dates back to the late 1800s when there was considerable oil exploration. Gas was detected as the drill bit passed through the shale, but early experimental attempts to harvest the gas were hindered by the excessively low shale permeability and other issues, according to Perry.
Gas-in-place estimates for the New Albany range from 90 to 160 Tcf, and technically recoverable volumes are estimated to range between 1.9 Tcf and 19.2 Tcf.
Still, the gas wells that have been drilled over the years have yielded limited quantities of gas.
“This combination of limited production and high volumes in place raises the question of why isn’t there more production,” said Perry, who noted “there’s a set of technically complex issues between the two.
“People aren’t sure how to frac, where to best locate the wells and so forth,” he added.
Two-Way Tech Transfer
The New Albany Shale occurs at surface outcrop and down to as much as 4,500 feet deep; both thermogenic and biogenic gas systems are present. Well costs for a horizontal well with hydraulic fracture stimulation range between $1 million and $1.8 million.
Production is primarily from natural fractures, and production in commercial quantities requires proper placement of horizontal wells relative to dominant fracture orientation. Owing to the extremely low matrix permeability and limited open natural fractures, interconnecting the fractures via hydraulic fracture stimulation is a must.
This can be a tedious task given that the New Albany is underlain by water-bearing Devonian rocks in some areas. Care must be taken to prevent the fractures from growing into the water-bearing zone.
“We’re now about a year into this project, and the team has conducted a couple of field experiments with partner operators in the area,” Perry said. “They’re looking at detailed core descriptions to better identify natural fracture patterns and formation evaluation issues to better control hydraulic fracture design.”
He noted there will be additional field tests to gather data for further study to try to resolve some of the production issues and others that are ongoing.
The project has the potential to benefit shale plays other than the New Albany.
“When we do a comprehensive study of this type, we’re always looking to see how far and wide the results might transfer to other geologic basins,” Perry emphasized. “Likewise, it’s been part of this project to take what learnings have taken place in the Barnett and other areas to see what might apply in this basin as well.
“It’s always a two-way tech transfer pathway that’s kind of ongoing,” he said, “just so we don’t duplicate efforts or reinvent things.”
Raising ‘the Curve’
It’s important to recognize that not all technologies applicable to shales translate to each shale.
For instance, the naturally fractured rock supporting biogenic gas generation in the New Albany isn’t readily similar to the other high-profile shale plays. Caution is necessary when attempting to transfer outside technologies to the New Albany.
Perry emphasized there are eight important areas that can contribute to a shale play’s success in different ways and varying quantitative values, and they should be investigated for every play. The importance of each of these can be different for each shale:
- Organic richness.
- Pore pressure.
A number of vertical wells have been drilled and fracture treated in the New Albany. Yet here as elsewhere, horizontal wells provide the opportunity to contact more natural fracture swarms and better contact the reservoir rock.
Initial gas production rates for a New Albany horizontal well with a 2,500-foot lateral are generally 275 mcf/d, declining to 100 mcf/d in the first 24 months. In fact, peak production volumes for these long-lived wells occur in the first 30 days, followed by a significant decline and then a shallow hyperbolic decline.
Cumulative estimated gas production over a 40-year period is one Bcf per well.
Initial high production rates followed by steep declines tend to be the rule for shale plays in general. As the New Albany demonstrates, post-decline production can continue for many years ultimately yielding significant volumes of gas.
Still, there’s room for improvement, and this is an industry comprised of folks noted for an almost uncanny talent for developing new technologies to overcome challenges.
The ongoing GTI effort is an example.
“We don’t think the results (of the project) will necessarily be to change that decline curve pattern, but to raise the whole curve,” Perry said. “Instead of initial production of maybe 200 mcf a day and declining rapidly, we might be able to get the initial rate up to 500 mcf a day and decline rapidly but then produce at a higher rate over that long period of time.
“The shape of the curve won’t change,” he said. “We’ll just lift it up a bit higher on the graph.”
Perry noted they are investigating optimum designs for fracture stimulation, along with the types of fluid to be used.
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Shahab D. Mohaghegh and Amirmasoud Kalantari with West Virginia University recently submitted a report as part of RPSEA’s Unconventional Resources Program, Project 07122-16. The report describes the impact of different reservoir characteristics, such as matrix porosity, matrix permeability, initial reservoir pressure and pay thickness, as well as the length of horizontal wells and their orientation relative to the dominant natural fracture system on gas production in the New Albany shale. The study utilized a publicly available numerical model specifically developed by the National Energy Technology Laboratory (NETL) to simulate gas production from naturally fractured reservoirs and analyze the variables and their effects on productivity. The study focuses on several New Albany Shale wells in western Kentucky.
Production from the wells was analyzed and history matched. During the history matching process, natural fracture length, density, orientation and fracture bedding of the New Albany Shale were modeled using information developed by the project, the Kentucky Geological Survey and the literature. Sensitivity analyses were performed on key reservoir parameters, natural fracture aperture, density and length to tune the model. The history-matched results of 87 New Albany shale wells were used for performing a novel integrated workflow.
Unlike traditional reservoir simulation and modeling, which begins from building a geo-cellular model, this model is a top-down, intelligent reservoir model that starts by analyzing the production data using traditional reservoir engineering techniques. These analyses were performed on individual wells in a multi-well New Albany shale gas reservoir in western Kentucky, that has a reasonable production history. Data-driven techniques were then used to develop single-well predictive models from the production history, the well logs and other available geologic and petrophysical data. The database created from the aforementioned analysis resulted in a large number of spatio-temporal snap shots of reservoir behavior.
Artificial intelligence and data mining techniques were subsequently applied to fuse all information into a cohesive reservoir model, which was calibrated (history matched) using the production history of the most recent set of wells drilled in the field. The calibrated reservoir model was then utilized for predictive purposes to identify the most effective field development strategies, including locations of infill wells, remaining reserves and under-performing wells. Capabilities of this new technique, ease of use and much shorter development and analysis time were demonstrated as compared to the traditional simulation and modeling in the study.
GTI: Iraj Salehi, firstname.lastname@example.org, (847) 768-0902
Wes Virginia University: Shahab Mohaghegh, Shahab.Mohaghegh@mail.wvu.edu, (304) 293-3984