VISAGE and geoLOGIC are happy to welcome Mark Haggerty, from Headwaters Economics as our guest blogger today. We are presenting a preview of a report expected out in the next few weeks.

Headwaters Economics is an independent, non-profit research group based in Bozeman, MT.  Their mission is to improve community development and land management decisions in the West.  Headwaters blends innovative research techniques and extensive on-the-ground experience working with a range of partners across the West for more than 20 years. Here is Mark’s posting…

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Headwaters Economics is using data from geoLOGIC Data Center and assistance from VISAGE to examine how US States differ in the amount and timing of tax collections on unconventional oil. 
The current oil boom has brought extensive changes to the rural, sparsely populated region of western North Dakota. Despite the benefits of jobs, tax revenue, and royalties, many communities are feeling overwhelmed by the rush of rigs and workers from out of state. 
Worries that current policy may not be making the most of this exceptional opportunity have prompted discussions in the North Dakota state legislature about how changes to tax policy could help the state and communities better manage the boom. 
Applying data and assistance from VISAGE and geoLOGIC Data Center, Headwaters Economics has analyzed how North Dakota, Colorado, Montana, and Wyoming approach the collection and distribution of energy revenue in the context of the unconventional oil boom.  The goal of the research is to provide decision makers in each state with good information upon which to make better decisions. 

The following figure shows the type curve for an average Bakken horizontal oil well which produced 157,222 barrels of oil over the first 36 months of production, peaking at an average daily rate of 372 barrels in the second month and declining to a low of 78 barrels per day in the thirty-sixth month (Figure 1: VISAGE calculated the calendar day average oil production type curve based on North Dakota, single leg horizontal oil wells producing from the Mbakken stratigraphic unit)

Using a price of 98 per barrel , an average well will  produce $15.4 million in cumulative production value in 36 months, peaking at $1.1 million in revenue in the second month and declining to $233,142 thousand in revenue in month 36.  

We used this average well profile to illustrate the performance of four Western U.S. state’s tax structure.  We compare the types of taxes levied, the effective tax rate, and the timing of tax collections relative to production. 
Ensuring that revenue is available in the place, time, and amount needed will enable state and local governments to best facilitate and manage drilling and production activities. The following two figures show that relative to Montana, North Dakota captures tax revenue early in the drilling and initial production phase.  In North Dakota, a sales tax recognizes revenue from drilling and support services, and two production taxes levied monthly ensure a short lag between production and revenue collections.  North Dakota’s average effective tax rate is higher over the first 36 months of production at 9.9 percent ($1.5 million in cumulative tax revenue) compared to Montana’s average effective tax rate of 4.6 percent ($716,254 in cumulative tax revenue) over the same period.  

Montana has no sales tax on drilling and support services, and grants an 18-month holiday on production from new horizontal wells, delaying significant revenue collection from new production for nearly two years from when impacts and infrastructure and services occur during the drilling phase.

Even with its comparative advantage in capturing more tax revenue more quickly from oil wells, North Dakota is experiencing difficulties in keeping pace with service and infrastructure needs. Montana, which collects less tax revenue in a less timely way than its neighbour, may have even greater difficulties responding to impacts of oil development when rigs eventually cross the border.  

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That concludes the preview of the upcoming report. Watch this blog for an announcement of that report and where to find it. The full report will include comparative data for Colorado and Wyoming, and additional analysis of how each of the four states tax unconventional oil and distribute the proceeds between state and local governments.   

For More Information Contact
Mark Haggerty
(406) 570 5626 
mark@headwaterseconomics.org
www.headwaterseconomics.org

In appreciation of this award we would like to extend our thanks to those that contributed to our success:

• Kory Galbraith at Elkhorn for nominating us for this award
• our visionary clients who constantly strive for better technology and inspire us to build it
• geoLogic for working with us to realize the potential of VISAGE analysis capabilities when combined with the geoLOGIC Data Center
• Garry Wilton and colleagues at KPMG Calgary for their assistance in helping us understand and benefit from SR&ED
• Brooke Campbell and James Jensen for their marketing and creative talents displayed in our website

Today’s blog will cover quite a spectrum of information including The Montney Players, the top wells, type curves and maps generated by taking VISAGE percentile information and plotting it in geoScout. So let’s jump right in….

The Montney Players

The top 12 companies (18% of the companies in the Montney) accounted for 90% of May’s production. Those same 12 companies have 79% of the producing wells. The chart below shows a breakdown of all of the producers with the following information being shown:  COMPANY (producing well count): (mmcf/day) % of Total production

Top 10 Wells (based on May 2011 production rate)

See this VISAGE Well Ticket (top 10 montney wells in may 2011) for more details about these wells.

Top 10 Wells (based on cumulative production)

See this VISAGE well ticket (top 10 montney wells in may 2011) for more details about these wells.

Type Curves Part 1: Comparison of Well Profile Types

Type Curves Part 2: Normalized Distribution of Initial Production Rates

Before we show any additional type curves of Horizontal Montney Wells it is important that we provide a context for what we will be looking at. The remaining horizontal well analyses will be for all producing horizontal wells that came on production in 2007 or later. This collection of wells has some massive producers that have the potential to significantly skew data results. therefore it is important when doing any of this analysis to support decisions that the collection of wells has been scrutinized by professional engineers and geologists familiar with the play. The follow chart identifies six anomalously large wells that fall outside the main distribution of initial rates (i.e. average of months 2 and 3).

Distribution of Initial Production Rates

 Type Curves Part 3: Comparison of Normalized Production Profiles by On Production Year

The best year for the Montney (in terms of average production profiles was 2007). Subsequent to that production profiles have tried to catch up to these rates, with 2011 looking to be the most promising. Something anyone analysing data needs to be aware for future analyses is that there was a temporary shut-in of production in May of this year. This will profoundly impact type curves as can be seen in the 2011 values in this chart.

Normalized Production by On Production Year

Type Curves Part 4: Percentile Trendlines

Another method for understanding the variability in production rates that make up a type curve are Percentile Trendlines (read about this VISAGE feature in our blog So What Is The Problem With Production Type Curves?). Here we can see that the average initial rate is about 2600 mcf/day, 80% of the values that make up this number fall between 331 mcf/day and 5295 mcf/day.

P10 to P90 Percentiles of HZ Well Type Curve

 

 Type Curves Part 5: How azimuth affects horizontal well production

How azimuth affects horizontal well production

Type Curves Part 6: How azimuth affects horizontal well rates vs cumulative production

How azimuth affect rate vs cumulative production

The evolution of the Montney has varied significantly between Alberta and BC. A good comparison of these provinces would be a long distance runner vs a sprinter. Alberta’s production has been quite steady since 1996, with slight deviations from its average production of 263 mmcf/day (peaking at 406 mmcf/day in Aug 2010). BC however has come out of the gate like a sprinter, averaging an 80% increase in production year over year since 2006. BC production rates surpassed Alberta for the first time in Feb 2009 and continued to grow to 3.5 times that of Alberta in May 2011. However, Alberta is ahead in terms of the total gas produced to date in the Montney, accounting for 69.4% of the 2,456 bcf of cumulative gas produced. So, if both provinces were to sustain the May 2011 rates how long would it take for BC to surpass Alberta in terms of cumulative Montney production? The answer is September 2014.

The big game changer in all of this is horizontal drilling technology. The 801 horizontal wells account for 89.6% of current production rates. 70% of the horizontal wells currently producing are in BC. The number of producing horizontal wells has had an average increase of 221% since 2007. Will 2011 numbers keep up with this pace?

So let’s take a look at the full Montney in a series of charts…

The Growth of Horizontal Wells

May 2011 production summary:
801 horizontal wells producing 1306 mmcf/day (89.6% of production) 
455 vertical wells producing 87 mmcf/day (6.6% of production)
266 deviated wells producing 60 mmcf/day (4.1% of production)
26 crooked wells producing 5 mmcf/day (0.3% of production)

Production Summary

The first Montney wells came on stream in July 1977 in Alberta. The most pronounced jump in production (in Alberta) started in November 1995 growing to 274 mmcf/day a year later. Total Montney production has grown to 1457 mmcf/day in May 2011.

• Total number of Montney wells that have produced = 2261 (excludes commingled wells)
• 89% of that production came on stream since Sept 2008
• First horizontal wells came on stream in Sept 2001 in Alberta
• 70% of the horizontal wells are in BC
• 21% of current (May 2011) Montney gas production came on stream in 2011
• 62% of current (May 2011) Montney gas production came on stream since Jan 2010
• Biggest growth in Production was in 2010, contributing 635 mmcf/day by Dec 2010
• Total BC Production in May 2011 (884 wells) = 1130 mmcf/day (78%)
• Total AB Production May 2011 (778 wells) = 327 mmcf/day (22%)

The chart above shows a comparison of production and producing well count in AB and BC.  Alberta’s well count has grown steadily since 1996 while sustaining a fairly constant production rate. BC’s well count and production have both grown rapidly since 2006. I superimposed the Henry Hub and Intra AB gas prices on this chart for your references (courtesy of GLJ). A collegue said this to me today, “There are a lot of factors driving Montney drilling over the last several years, including changes in Alberta royalties, drive to prove up reserves at any price … price of gas is only 1 factor, but obviously an important one.”

• Cumulative Montney gas produced to date = 2,456 bcf
• Cumulative Alberta Montney gas produced to date = 1,704 bcf (69.4% of total)
• Cumulative BC Montney gas produced to date = 752 bcf (30.6% of total)

Stay tuned over the next week or two for more on the Montney. As always we welcome your feedback and suggestions about what you would like to see in upcoming blogs.

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Disclaimer of Analysis Results
It is important to note when doing any of this kind of analysis that the selection of wells be scrutinized for meaningful results. The results presented are intended to fuel your understanding of VISAGE capabililties with gDC data. We would be happy to run analyses for specific well lists that you may have. Please feel free to contact us.

Data Disclaimer: gDC is the data source for the information presented in this blog post. If you see issues with the data or have concerns about the well list used for this posting please contact us.

There will be 2 more Montney blog posts coming up in the next week here at VISAGE and geoLOGIC.

My original intention today was to provide you with a detailed overview of the Montney Play. That was until a significant drop in BC Montney gas production caught my eye… so I have decided to focus on that for today’s blog. 

Montney Now Accounts for 30% of BC’s Gas Production
In the last 4.5 years, Montney has grown from 2.5% of BC’s Gas production to just over 30%. Of the recent 12.7% drop in BC gas production, Montney accounts for 32% of that. So what is triggering this drop in production and who in the Montney has been affected? The key contributor was a temporary shut-in due to the scheduled McMahon gas processing plant turnaround. 

A Closer Look at the Montney

Montney production in BC has dropped 13.4% (151.6 mmcf/day) from May to June. This drop is attributable to only a 3% drop in producing wells (which works out to 23 wells seemingly affected by the plant turn-around). For your interest I have also included the Nymex spot price on this chart to show that Montney growth has continued in spite of lower gas prices.

 The Significant Seven

 There are seven companies who appear to be hit the hardest by the temporary shut-in. They have all seen a drop from May to June of greater than 5 mmcf/day. Collectively they account for 92% of the recent drop in BC Montney production.

Stay tuned over the next week or two for more on the Montney. As always we welcome your feedback and suggestions about what you would like to see in upcoming blogs.

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Disclaimer of Analysis Results
It is important to note when doing any of this kind of analysis that the selection of wells be scrutinized for meaningful results. The results presented are intended to fuel your understanding of VISAGE capabililties with gDC data. We would be happy to run analyses for specific well lists that you may have. Please feel free to contact us.

Data Disclaimer: gDC is the data source for the information presented in this blog post. If you see issues with the data or have concerns about the well list used for this posting please contact us.

In our previous blog post we looked at the growth of the Bakken and who the main players are.  When looking at type curves and the variability of the associated data, it becomes very clear that there are many, many factors that need to be considered when doing type curves. The most important consideration is the selection of wells that are comparable and representative of a particular location or situation.  Some things to consider in the Bakken are leg count, frac count (if any), horizontal length, location, horizontal azimuth …. and the list goes on. We’ll show you how the horizontal Bakken wells (since 2007) collectively behave and how much they vary. We can hone in on some more specific analyses with your help (please post your comments).

Take 1: Type Curve (Rate vs Time)
 

This chart shows the following for Bakken Horizontal Wells post Jan 2007:

• The average rate vs time “type curve”, which is the average of producing wells
• The P90 and P10 percentile trendlines (these represent the boundaries in which you will find 80% of the wells. Percentile trendlines are discussed in detail in our blog “So what is the problem with production type curves?”
• The P50 is the median (i.e. half the wells are greater than this number and half the wells are less than this number).
• The type curve of cumulative production (used to help estimate expected payout on a new well). If you are interested in seeing this with P90 and P10 lines please let us know.
• Producing well count  is important when doing any kind of type curve as it tells you how many wells contributed to the mean value calculation. When this value gets too low, the sample size may not be large enough to be representative.

Take 2: Percentile Distributions

In our last blog we looked at how the production rates have been changing over time and noted that early indications are that 2011 wells will outperform previous years. An increased understanding of the play combined with drilling and frac technology have had a profound impact on what we can expect from the Bakken. Visual tools like percentile plots can help communicate just how variable the data is. In this chart each dot represents a well. The colours represent different years. While we can see the P50’s have evolved with each production year, the values seem to have a similar range of variability each year.
 
Are Initial Rates a Good Measure of Performance?
Last blog we also looked at the top 10 wells in the last year. It was pointed out to me that there are many criteria for what a “top well” is. Initial rates are one way of measuring wells, but in some circumstances you may choke back a well for sand control … in such a  case that well may look better in the context of cumulative production in the first 6 months. Let us know what your criteria are for measuring “top wells” by posting a comment.

Take 3: Horizontal Direction (Rate vs Time) 

Type curves are more than just a means of characterizing “typical” well behaviour, they are a visual tool for comparing collections of wells. In this case we can see that the direction the horizontal well was drilled (i.e. azimuth) impacts production behaviour. The notable aspect of this chart is that while E-W wells do not appear to have the best initial rates, they tend to sustain a better rate after 9 months of production than other orientations.

Take 4: Horizontal Direction (Rate vs Cumulative Production)

Another visual tool used to compare well collections is a normalized rate vs cumulative production type curve. This allows us to compare how rate changes with cumulative production over time. I chose month 32 as an example point of comparison.

There you have it. Four takes on play analysis and well behavior in the Bakken. If you found this interesting or would like to see other analyses please post a comment.
Stay tuned for more analysis in the next few days!

Disclaimer of Analysis Results
It is important to note when doing any of this kind of analysis that the selection of wells be scrutinized for comparable, meaningful results. Given we are looking at the play in its entirety, the results presented are general and are intended to fuel your understanding of play analysis. We would be happy to run analyses for specific well lists that you may have. Please feel free to contact us.

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Special thanks to geoLOGIC systems for providing VISAGE access to data from the gDC (geoLOGIC Data Center)

Data Disclaimer: gDC is the data source for the information presented in this blog post. The well list used was provided by an independent geologist. If you see issues with the data or have concerns about the well list used for this posting please contact us.

The Growth of the Play
The Bakken has been a hot play in recent years and has grown to almost 70,000 bbl/day oil production (in SE Saskatchewan). Almost all of the Bakken growth is attributable to horizontal wells. Here are a few stats:
Well Stats
Total number of Bakken wells that have produced in SE Sask = 2178
88% of these wells came on production since Jan 2007

• 2020 Horizontal Wells
• 150 Vertical Wells
• 6 Deviated Wells
• 2 Crooked Wells

Production Stats
Current Bakken Production is 69,916 bbl/day oil.
19% of that production came on stream in the first 3 months of 2011 (13,292 bbl/day).
The biggest production growth in one year was 2008, a production rate increase of 41,335 bbl/day by Dec 2008.
If production growth continues at the same rate, we can expect 2011 production increases to exceed 50,000 bbl/day … time will tell.

The Growth of the Players
The growth of the Bakken goes hand in hand with the success story of Crescent Point. Crescent Point has grown consistently in the last 5 years and continues to dominate production in the Bakken.  However, Petrobakken has been running a close second, at times equaling Crescent Point’s production in 2009 and 2010. The next two images show how the players have evolved in the Bakken and a breakdown of the top companies so far in 2011.

How are 2011 Production Rates measuring up?
Early indications show that the average production rates in 2011 are exceeding those from previous years. The following chart tells an interesting story. Horizontal well technology started to blossom in the Bakken in 2007. In 2008 through 2010, production rates maintained a similar type curve profile. The 151 wells that have come on stream in 2011 are showing about 10% higher initial rates than 2010.

Top 10 Producing Wells
The number one request I have had from friends and clients is “Show me the top producing wells”. Well, here they are. The selection of the top producing wells is based on the 2nd month production rate for horizontal wells that came on production since Jan 2010. I have also included the top 10 well tickets.

So what’s coming next?
Well that depends somewhat on you? Continue to  follow us here or at geoLOGIC and please post a comment with your suggestions about what you would like to see (or if you like what you have seen thus far).
Here are some ideas:

• Well Performance: type curves (rate vs. time and rate vs cumulative) with percentile trendlines (see a previous posting for technical details on this). We’ll take into account things like frac count, leg count, azimuth …
• Company Performance: comparing companies to see who gets better initial rates, who can better manage their declines, who’s growing faster ….

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Special thanks to geoLOGIC systems for providing VISAGE access to data from the gDC (geoLOGIC Data Center)

Disclaimer: gDC is the data source for the information presented in this blog post. The well list used was provided by an independent geologist. If you see issues with the data or have concerns about the well list used for this posting please contact us.

Normalized type curve analysis (rate vs time) provides a consistent comparison tool for production. Often used for well analysis (e.g. frac count, horizontal length, azimuth), normalized type curves are also valuable for comparing companies. This chart shows how several companies compare to one another and to the play average.

So What Is The Problem With Production Type Curves?
The problem with type curves is that the range of values used to calculate the average (type curve) are in no way represented in the type curve. I have a client who tries to understand the range of values that make up the type curve by showing all of the wells on one chart. As you can see, it does give you a sense of the range of values, but is a bit messy to look at. Maybe there is a better way to communicate and understand this?

This chart shows the normalized production profiles of the 323 wells that were used to calculate the (average) type curve. The type curve is shown as a thick dotted red line. This is a bit messy to look at.

Introducing Percentiles to Type Curves

One technique that the industry uses to understand and quantify distributions of data is percentiles (or cumulative probabilities). This organizes the distribution into increments between 0 and 100. You can then take, for example, the 10th percentile or P10 number (I’m using a “less than” convention for percentiles in this example) and say 10 percent of my wells will have a value “less than or equal to” my P10 value. The location of percentiles on a typical lognormal distribution would look something like:

This is a typical lognormal distribution showing the locations of the P10, Mode, Median (i.e. P50), Mean and P90. These are all common reference points used in the industry.

Percentile Trendlines

At VISAGE, we came up with an innovative visual analytics technique to address “the problem with type curves”. If we take the percentile concepts and apply them to production trends then we can assemble monthly percentile distributions together to create “percentile trendlines”.

The image on the left shows a percentile distribution for values in a single month. VISAGE calculates this for each time period and assembles these into percentile trendlines. We also include the Swanson's Mean which is an estimate of the average values calculated by taking (0.3 x P10)+(0.4 x P50)+(0.3 x P90)

 
 The result of these calculations for a percentile trendline look something like:

Here we can see how the P10 and P90 percentile trendlines represent the 80% confidence interval of "reasonable results". The image on the right shows how we can get rid of the "noise" but still understand how varied the data is.

Hopefully, what I have shown you today has provided you with some insights into an innovative way to understand and communicate distributions of production data. We will be using this in some future blogs to help you understand the degree of variability that exists in some of the hotter plays today  (follow us here or at geoLOGIC). Some plays you can expect to see include Viking, Montney, Cardium and Bakken. We welcome suggestions about what you would like to see. If you have any suggestions, contact us, or post a comment here!

We invite you to participate by telling us what you would like to see in this series. If you have an idea please let us know at info@visageinfo.com.

In the mean time here are some examples to whet your appetite.

Alberta has had 310,961 wells that have produced oil or gas. In this chart we can see oil production in Alberta since 1962 grouped by on-production-year (i.e. each coloured band represents the production for wells that came on stream in a particular year).

Saskatchewan has become a major player in oil production in the WCSB. Also note the peaks and consider the role oil price has had in defining these peaks.

This shows a breakdown of historical gas production in the WCSB and denotes the top 14 producers. Note the impact that release from gas storage has had on recent production increases.

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Special thanks to geoLOGIC systems for providing VISAGE access to data from the gDC (geoLOGIC Data Center)

Best Map: National Geographic, for “Rivers of the World,” a gorgeous map of the world’s rivers and lakes.

Best of Show (print): National Geographic, for “Gulf of Mexico: A Geography of Offshore Oil,” the story of oil drilling and drilling rights, primarily along the coast of Louisiana.

And my favourite, is a compelling video about Mariano Rivera pitching.

Best of Show (online): New York Times, for its demonstration of Mariano Rivera’s unique pitching style, titled “How Mariano Rivera Dominates Hitters.” Take the time to watch this amazing combination of narration and motion graphics.

One award that wasn’t mentioned (but in my opinion should have been) in Stephen Few’s blog is Oil Spill: Tracking the Spill in the Gulf which won gold for online breaking news by the New York Times. A step by step visual that details the progression of the oil spill very effectively without attempting to be too flashy.

For a complete list of all of the awards check out Infographics News.

And as an added bonus there is Stephen Few’s presentation from the summit entitled “Infographics and the Brain: Designing Graphics to Inform.”