As development of unconventional resources in the U.S. continues, the Eagle Ford Shale has emerged as one of the country’s most active shale plays. Since the play’s early beginnings, oil production has increased significantly, from an average of 352 bbl/d in 2008 to 8.38 Mbbl/d in April 2014, as reported by the Texas Railroad Commission.

The reservoir characteristics of the Eagle Ford make it a prime candidate for hydraulic fracturing. One of the highest costs incurred in the fracturing treatment is the proppant, which also has a significant impact on well performance. This emphasizes the need to find the optimal proppant type, design and volume based on well conditions and budget.

The main proppant types commonly used in fracturing treatments are uncoated frack sand (UFS), resin-coated sand (RCS), uncoated ceramic (UC) and curable resin-coated ceramic (CRCC). Traditionally, RCS, UC and CRCC are labeled “premium” proppants for their higher performance and price compared to UFS. RCS has two proppant types: curable resin-coated sand (CRCS) and precured resin-coated sand (PRCS). CRCS has the ability to control proppant flowback, minimize embedment, help prevent proppant fines migration and enhance long-term production. PRCS is an older technology with fewer benefits than CRCS.

As oil and gas technology progresses, job sizes have increased, and proppant designs have changed. According to a study by PacWest Consulting Partners, the average proppant volume per well trend in the Eagle Ford rose about 50% from 2011 to 2013. In 2014, proppant volumes have been reported in excess of 14 million lb per well.

A three-part study was published that performed a statistical analysis of more than 2,500 wells in the Eagle Ford, finding that factors such as proppant volume and measured depth of the deepest perforation were statistically significant to impacting three-month boe production (SPE 158501).

Proppant trends

In a case study compiled by Momentive Specialty Chemicals Inc., a similar methodology was applied but with a narrower focus. Only two offset Eagle Ford operators were chosen so that specific completion details (such as proppant type and volume) could be correlated to production over a three-year period. These operators were chosen based on proximity to one another and their selection of very different proppant types. Operator A uses CRCS, while Operator B uses UFS. Both operators are in the same county in the oil and condensate window.

Production and completion details from all wells spanning 2011 to early 2014 were in the initial dataset for each operator. Of the more than 340 wells studied, only 3% were removed due to having less than three months of production. This was done to ensure accurate trend prediction and was the only change made to the dataset throughout the entire case study. The number of wells was roughly split 2:1 from Operator A to Operator B.

Each well was categorized based on the length of production time to ensure that wells completed in similar time periods were compared to one another. In theory, an operator should see production improvements over time based on ongoing completion optimization efforts since wells completed three years ago can be very different from wells completed three months ago. Each well was assigned a production time frame and only appeared in a single dataset ranging from three to 36 months.

Analysis was focused on comparing completion factors, cumulative production, decline curves and their resulting statistical correlations.

Completion factors such as proppant volume, production interval (the distance from the upper perforation to the lower perforation along the lateral) and true vertical depth (TVD) were averaged for each dataset. In addition to calculating averages, all data were loaded into statistical software to look at the data distribution to allow a more comprehensive analysis of the data.

Main findings

The main takeaways from the histogram analysis of completion data are:

  • Average total proppant volume per well for Operator B (~9 million lb of UFS) was more than twice the proppant volume per well of Operator A (~4 million lb of CRCS) and was the largest difference between operators over all the completion factors analyzed; and
  • Operator B had 20% longer production intervals and 10% deeper wells than Operator A.

Next, cumulative production graphs and decline curves were generated that looked at three comparisons: each operator vs. itself, Operator A vs. Operator B and production normalized by proppant volume. Oil, gas and boe were analyzed independently, but only boe results will be discussed in this article. Main takeaways:

  • Both operators showed production increases over time, which supported well segmentation by time frame;
  • For wells with six months or less production, Operator B averaged 32% higher boe production with double the proppant volume of Operator A. Operator B averaged a 43% decline, while Operator A averaged a 24% decline;
  • For wells with 24 months or more production, Operator A had 28% higher boe production with around half the proppant volume. Operator B averaged an 89% decline per well, while Operator A averaged a 70% decline per well;
  • Cumulative boe/lb of proppant was roughly twice as high for Operator A; and
  • Based on historical declines, if Operator A switched to Operator B’s design, an additional 16 wells per year would have to be drilled to maintain the current production rate.

Finally, statistical analysis examined the cumulative production (oil and gas independently) for each well and compared against each completion factor as well as the interaction between factors. Statistical software was used to run regressions to determine which factors are significant and which will have a more positive impact on production.

Six months and 24 months were chosen as goalposts to represent short- and long-term production. CRCS had a greater benefit at both time frames. However, proppant volume also was very significant to upfront production.

Similar results were shown for gas; however, TVD was significant to both time frames, and deeper wells were shown to have more gas production.

Further testing

Further support of why CRCS has a positive impact on production is shown in laboratory testing. Tests showed that UFS generates 16 times more fines than CRCS when exposed to wet, hot crush testing under conditions similar to the Eagle Ford. This will significantly decrease the effective conductivity, which is evident in the long-term production results of UFS compared to CRCS (SPE 135502).

Based on the analysis, the additional upfront production seen by Operator B may be driven more by the increased proppant volume over Operator A. To maximize production and decrease decline rates, increased volumes of CRCS should be used. Although CRCS has a higher cost than UFS, further analysis shows that the return on investment by doubling the proppant volume of Operator A would be two months based on a 20% production increase.

There are many other factors (such as choke size and pump rate) that can impact production. However, out of the factors that were analyzed in this case study, proppant volume and proppant type were confirmed to be statistically significant to impacting the production. Although the strategy for developing an asset will vary from operator to operator, it is important to make sure that industry trends do not take the place of historical well analysis and experimentation.

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