What the data can tell us

The unconventional revolution may have changed the landscape of the oil and gas industry, at least in North America, but it’s also rewritten the playbook in terms of what operators thought they knew about producing oil and gas.

Shale reservoirs do not behave like their conventional brethren, and operators struggle with everything from flow physics to field development. It was with these uncertainties in mind that Siddhartha Gupta and Raj Banerjee of Schlumberger set out to study public data to draw some conclusions about unconventional reservoirs. Their findings are outlined in URTeC 1873063, “Leveraging the Power of Public Data to Solve Multiple Challenges in Unconventional Reservoirs.”

The authors spent six months culling public data to determine their findings. “This is one of the few studies conducted involving the use of public data and the first to cover the spectrum of reservoir from completion to production,” Gupta said. Much of that time was spent conditioning the data, he added. “Gathering unstructured data like weather patterns and pipeline information required significant time,” he said. “Since this was a unique study, there were several moving parts involved in it, and planning the workflows so that each tied in seamlessly into the next was critical.”

The goal was to develop a workflow that could honor a variety of data types without being overwhelming. “High well counts increase the volume of data, which makes it overwhelming to analyze on a typical spreadsheet,” the authors noted in their abstract. “Integrating efficient data management with seamlessly integrated analysis tools makes it much easier to understand the data and interpret the results.”

FIGURE 1. Screening for refracks allows operators to eliminate a large percentage of wells that will not benefit from the procedure. (Source: Schlumberger)

The study

The authors used the seven major shale plays in the U.S. as a starting point for the study. They examined data from more than 60,000 wells and 100 million data points. These data types included production rates; completion information such as proppant volume, fracturing fluid volume and stages; well locations; operating companies; and well test data.

Part of the study was to determine why certain operators performed better in certain plays. “In almost all of the basins, the top five operators (in terms of average liquid or gas production per well) complete their wells with less resource consumption (proppant and fluid) than others while producing more hydrocarbons,” the authors noted. “Either these operators are located in the better part of the basin, exposing them to a higher quality reservoir, or they are using engineered completion techniques to fracture their wells with less resource consumption [while] delivering a better well.”

Certainly some operators do have a geographical advantage, they noted. In the Eagle Ford, for instance, the top five operators are located in the northeast corner of the field, and the sixth operator, whose acreage sits outside of this sweet spot, has laterals that average 1,463 m (4,800 ft) longer than the top five. “A longer intercept with the reservoir helps in offsetting the location disadvantage,” they noted.

The Bakken, on the other hand, lacks this sort of explanation, leading the authors to surmise that the use of reservoir characterization and an engineered approach are the keys to success in this field.

This kind of analysis can be useful in identifying refrack candidates. Figure 1 shows a crossplot of a production index against a completion index. Wells in the highlighted quadrant are good producers even without optimal completions and are therefore good refrack candidates. The authors noted that this method can be used to eliminate 85% to 90% of potential refrack candidates that have already been completed optimally and therefore are unlikely to benefit from a recompletion.

Decline curve analysis

Decline curve analysis also is challenging in shale wells. The authors devised a fit-for-purpose technique in which a flow regime is applied to make sure the well has not yet reached boundary-dominated flow. For these wells, a Duong method and a power law technique are used, which provide more accurate results than the Arps technique. When applied to the entire 4,000-well population of the Eagle Ford Shale, these methods provided good curve fits (Figure 2).

FIGURE 2. Oil (left) and gas (right) production is forecast for one well using the three techniques: green and red, Duong; purple and blue, power law; and gray and orange, Arps. (Source: Schlumberger)

Well trajectory

To determine trajectory effects, the authors used a transient flow simulator. Three wells were chosen and were toe up, toe down and undulating. Inflow and pressure-volume-temperature were maintained for all three wells.

A simulator was run for two hours, after which the flow dynamics were observed. The authors noted that the toe-up well had some gas buildup near the heel, although slugging was minimal. The undulating well had gas buildup in the low point of the well, and the toe-down well experienced liquid buildup near the toe that caused slugging along the entire lateral length.

“When drilling a well, these factors must be considered because chasing the dip of the formation can sometimes result in a well that has extreme slugging and does not drain effectively,” the authors noted.

Next steps

Now that the first study has been completed, Gupta said, subsequent studies should go more quickly since the structure of the workflow is in place. The initial study was conducted using commercially available tools, mostly from Schlumberger, although a third-party application was used for the business intelligence tool that delivered the high-level visualization. He said that Schlumberger is currently expanding its data analytics portfolio to create “an end-to-end solution encompassing this study and other geological workflows that have been created by other Schlumberger groups.” Schlumberger also offers consulting services for these types of studies, he added.

Since there was no operator directly involved in the study, Banerjee added that it’s difficult to say that a study like this has augmented anyone’s decision-making process. “However, all of the steps in this workflow are backed by technology highly relevant to the unconventional market, making it useful for any operator large or small,” he said. “Independent companies have an even greater advantage in that their own production, completion and reservoir data are far more granular than what is available in the public domain. This makes it much easier and more valuable for them to do a study like this to refine their decision-making process.”