NGFE Reports: From a Stream to a Trickle

Predicting well performance of shale plays over time

What was once an extremely productive shale gas play can change quite dramatically. That’s what Italian energy concern ENI has experienced at the Barnett shale play in Texas.

“It’s food for thought,” said ENI’s Antonio Ciuca, Production Optimization Engineer, of the critical initial production of a shale gas well in the beginning and it’s steep decline later. He showed a graphic of just such a big production drop at the Global Shale Gas Summit in Warsaw, Poland.

Headquartered in Milan, Italy, ENI is an integrated energy company active in more than 70 countries. With exploration and production operations worldwide, ENI is also present at the Barnett shale, said Mr. Ciuca.

“If we follow up the evolution of the gas shale plays in North America, Europe is the next step. We are almost in a mature situation to move the whole thing to Europe.”

“Not all shales are alike,” explained Ciuca. “But there are common factors for all shale plays. Whenever dealing with shale you need an intensive and complex operation, which means numerous wells in short time frame. The economics require a low-cost solution with high reliability.”

He said that each component had to be optimized as part of a more complex system.

“Assume you have 10 square kilometers. If you drill 500 wells, with frac ponds, the wells must be connected so we need gas pipelines inside the field. It’s complicated, and there are numerous activities that need to be performed.”

Ciuca spoke about a drilling operation’s “pad approach.” “On a small surface where you can drill numerous wells, you’re minimizing the impact on the surface location. For stimulation you can use techniques quickly and with more efficiency like simultaneous fracing.”

Minimizing footprint was important, he said, and was the biggest challenge for the industry. “We can be in a very populated area like Marcellus and we’re drilling close to houses, so minimizing the footprint is the big challenge of the future. Technologies are working in that direction, like the pad approach,” he said.

“Longer laterals also allow you to drill less wells. The recycling of water is also crucial. Minimizing its use would be a great thing for the entire industry,” Ciuca explained.

“Hundreds of wells means thousands of operations must be performed in sequence, and these things conflict with each other. So to plan perfectly and minimize non-productive time can have a huge effect on production itself.”

According to Ciuca, the spacing of wells, average well length and the size of the treatment jobs are all crucial: “The first result is that whenever we drill longer laterals (2-4,000 feet) you can really bring down the average costs, by 30-40%. But if they’re longer than that, they don’t perform as well.”

It also takes time, he said. There’s also an impact from the spacing of the well. “We chose different spacing for pads – close by and faraway. Spacing of 125 feet showed a successful result.”

He added, “We’ve collected the data, and created a database with this info to create a model which enables us to change some of the parameters to give us a different production profile. We’re looking forward to using this model somewhere else, but it must be calibrated with a good database.”

“Finally,” Ciuca concluded, “we’re facing a huge number of operations so in terms of efficiency it’s crucial. Optimizing and integrating all the parts is the key to success.”

“It’s really a continuum of learning that we’re going through with shale gas plays,” said Deborah Provias, Technical Manager Devonian Shale Gas Team at Canadian energy company Nexen. “We can understand but not predict, but we’re getting a handle on the kinds of things we can control. But models are at a very early stage.”

The title of Ms. Provias’ presentation was Shale Gas Productivity – Can we understand, control, predict.

“It’s a difficult topic and I’ve been thinking about it in the last four years as I’ve been working on shale gas,” said Provias, who explained that Nexen is a Canadian company based in Calgary, Alberta focused on heavy oil recovery, conventional E&P and unconventionals.

Nexen started exploring coal bed methane and ended up with shale gas in northeastern British Columbia.

“We’ve recently doubled our acreage position,” she said. “We’ve got a lot of land and need lot of time to develop it.”

In her presentation, Ms. Provias said regarding this there were a number of things, which may be misunderstood – she listed them.

“Shale gas accumulations tend to be extensive. Using a manufacturing style of development keeps things consistent, but the challenge is that the shale is heterogeneous within a core, which makes it tough to apply this manufacturing technique.”

She said, “The second thing to remember is that unconventional plays are similar to conventional in that you need to know where the gas is. Fracability is key - if you can’t break, it you’re not going to get any production.”

Developing a predictive capability, said Provias, was critical to frac efficiency and frac effectiveness: doing it in the right spot, breaking things that are maybe already broken, and being careful about what you’re trying to break.

She also spoke about dominant flow mechanisms and said the time frame is different for every shale gas play.

Provias explained, “It takes one year for one gas molecule to move one meter, which is key to understanding the fracability of the rock. The time scale on the bottom access is 10 years, I’d like to point out, so there’s not a lot of precedent to be able to extrapolate.”

She said micro-seismic provided insight. “If you have two well bores, and the shorter one was started a year earlier, you may have ever frac stage pumped in the same way, but a significant variation in fracturing activity. What that says to me is that the sequence of events and how you develop a field is very important. Things get very complicated with geological hazards.”

Predictive abilities, Provias contended were based on data, analogy, and empirical analysis, as well as understanding flow mechanisms and time components.

“The key to any modeling approach has to be that integrate workflow, involving four areas: frac stimulation optimization, dynamic reservoir modeling, natural fracture modeling and static earth modeling (an integrated modeling approach).”

As for how to you join up a reservoir and a fracturing system, she showed four different methods being used for prediction.

“We’ve come a long way in understanding which factors are important,” explained Provias, “and we can control certain things; predictive capabilities are improving but it’s about finding the right balance.”

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