Frac Analysis In VISAGE: How Adding More Stages Impacts Gas Production

April 28, 2014 by

Editor’s Note: While VISAGE rebranded to VERDAZO in April 2016, we haven’t changed the VISAGE name in our previous blog posts. We’re proud of our decade of work as VISAGE and that lives on within these blogs. Enjoy.

VISAGE has been working with several clients to integrate production data from the IHS Information Hub with frac data from the Well Completions and Frac Database (by Canadian Discovery Ltd). The ability to analyse the production impact of completion technologies in a visual interactive way has provided our clients with competitive and strategic insights that weren’t easily achieved using other software. This is the first in a series that illustrates some of the analyses that are possible. To do this we invited Jim Gouveia to comment on “how, and why, production per stage changes as more frac stages are added to a well”.

Interview Guest: Jim Gouveia, Partner, Rose & Associates LLP. Jim has more than 33 years of industry experience and has been a thought leader in using Statistical Approaches for Effective Economic Modeling. He has co-authored and presented several papers, including being a contributing author on the SPEE’s 2011 Monograph 3, “Guidelines for the practical evaluation of undeveloped reserves in Resource plays”.

VISAGE: It is generally perceived that adding frac stages to a well increases the wells production. If we look at distributions of cumulative gas production in the first 12 months of 1317 Montney horizontal wells, grouped by number of stages, what would you say about a chart like this? (Note: all wells have had at least 12 months of production)

 12-Month-Cum-Gas-Per-Well

 Jim G: There is clearly a trend towards higher well rates with more fracture stages.  To truly determine the impact of increased fracture stages alone we would need to add some additional filters, such as; operator, type and amount of frac fluids, cluster spacing, horizontal well length and the staging plus the amount of proppant . The variability of all of these frac characteristics are inherent in the distributions shown. We know that the industry trend has generally been toward bigger fracs, with more proppant and more fluid.  What we can see from this plot is that the combination of all of the above has been working.

What is interesting is that the distribution for the 9 to 13 stages is clearly better than the 5 to 9 stages.  The trend for 13 to 17 is similar across much of the distribution.  As expected we see additional mitigation of the downside as we introduce more stages.  The results for 21 and more stages would be genuine cause for a pause and re-assessment.  Again we would need to filter the data to assure that we have a consistent operator and technology being employed.  However, if they were consistent, the data would suggest that we have over capitalized when we have in excess of 13 stages.

Determining the optimal number of stages is an exercise in economic optimization which we will cover in detail in our upcoming blog. For now let’s consider how many stages will maximize rate. The answer will be driven by many factors, one of the most critical factors being the rock matrix itself.  If there is a pre-existing fracture network in which the fractures have been annealed, then less stages will be required.  In a very tight matrix where we are generating bi-wing, as opposed to complex, fracture networks we will need a lot more stages.  Understanding the local stress regimes will also play a role.  There are unique areas in the Montney and Duvernay where we have a scenario akin to the Barnett, with no predominant stress regime and as such, complex fracture networks are to be expected with fewer frac stages required.  So understanding the underlying Geology will be important before drawing conclusions as to the optimal number of fracture stages in a well.

Diagnostic plots like these in VISAGE can quickly help us ascertain whether our existing Geological sweet spot maps are in fact identifying where the productivity sweet spots will be.

 

VISAGE: However, as you increase the number of stages, does the relative contribution per stage decrease? If we look at distributions of cumulative gas production per stage in the first 12 months on 1357 Montney horizontal wells, you can clearly see that the production per stage appears to decrease with the addition of more stages. I asked Jim Gouveia from Rose and Associates to share his insights …

 12-Month-Cum-Gas-Per-Stg

Jim G: All other factors being equal, our expectation should be that as we increase the number of fracture stages we will initially see linear gains and then we should see diminishing returns.  At what point this will occur will be driven by the Geology as well as the frac design.  In the scenario where we are developing simpler bi-wing fractures with minimal width, the number of fracture stages required will be a function of the reservoir’s matrix permeability.   The tighter the rock matrix the closer we will need to put the stages to efficiently drain a given volume over say a 20 year period.  The length of time to consider in your design should be a reflection of your company’s discount rate and expected rate of return, and as such, should be relatively unique to your firm.

When we have a stress regime and rock mineralogy which is conducive to complex fractures, then the width of our Stimulated Rock Volume (SRV) will be driven by the type of fluid, and how much fluid is pumped per stage.  Technology will also play a part, as Zipper fracs, Pulse and Highway fracs will be more efficient at generating new SRV.  Assuming all the wells used the same fracturing technology, with the same cluster spacing (do they ever?) and that we are generating complex, or so called brittle failure fractures, then we will see similar patterns to the bi-wings.  The major difference being that much fewer fracture stages will be required, especially if Zipper fracs are used.

What we are observing in the plot of 12 month cumulative gas production per stage is interference between stages early as the number of stages increases.  Note that the plot for 1 to 5 stages is much higher on average than 5 to 9 and the others.  What we are seeing is that the impact is observed in the best wells and not noticeably in the poorer wells.  This makes sense as rate has been shown to be proportional to SRV.

The best wells will have the greatest SRV.  As we add more stages the good wells, with larger SRV, will be impacted sooner.  We will see overlapping stage SRV’s, where stages interfere with one another and compete for drawdown.

In the poorer wells we have limited SRV’s and as such there is a lot more area between the stages to optimize in terms of developing a stimulated rock volume.  Notice the limited deviation in the curves (on the poorer performing well portions of the distributions) between 1 to 5 stages and 5 to 9 stages and to a lesser extent on the 9 to 13 stages.

Sources:

Production Data: IHS Information Hub

Frac Data: Well Completions and Frac Database from Canadian Discovery

Visual Analysis: VISAGE

Thanks for reading. I welcome your questions and suggestions for future blogs.

Some other blogs you may find of interest:

About VISAGE – visual analytics for the petroleum industry
VISAGE analytics software equips operators and analysts in the petroleum industry to make the most valuable and timely decisions possible. VISAGE brings together public and proprietary oil and gas data from multiple sources for easy to use interactive analysis.