-Originally posted Oct 23, 2013-
The advent of big oil and gas data has transformed the energy sector. It has created a more cost-effective approach to hydrocarbon exploration across the industry.
Because unconventional oil and gas production requires more expensive drilling and completion technologies, energy companies of all sizes now rely heavily on oil and gas data to minimize drilling risks and create optimal production results.
Think Moneyball meets oil and gas.
The Moneyball Big Data Story
In 2002, General Manager Billy Beane shifted the recruiting focus of the Oakland Athletics. The team went from seeking inexpensive talent to using a highly analytical, evidence-based sabermetric approach to choose players.
Despite having the third lowest team payroll in the league, this strategy reinvigorated the franchise. It helped the A’s become respected contenders in the 2002 and 2003 playoffs.
The organization also set an American League record for consecutive wins as they had carved a competitive and strategic advantage due to their “analytic maturity.”
How Moneyball Applies to Oil and Gas Data
Although it is more commonly associated with unconventional production from shale, the oil and gas data revolution can also have a positive impact on companies and operators targeting conventional reservoirs.
While large scale capital expenditures associated with unconventional resource data may not be applicable to all conventional projects, smaller companies and operators can take advantage of the oil and gas data era without compromising individual project economics.
For example, spatially enabled big oil and gas data activity as represented in updated mineral leasing maps benefit both large and small operators in the conventional exploration space by identifying areas where leasing opportunities do not exist, allowing operators to quickly modify their leasing programs.
It is also hugely helpful to operators whose business models require them to look outside the current industry hotspots. Having “big data” rollups that can easily be searched with appropriate filters accelerates identification of true oil and gas opportunities that meet or exceed internal RIO hurdles.
Oil and Gas Data Integration and Creating Controllable Scalability
In an era when conventional reservoir “discoveries” have become increasingly rare, companies must be creative with how they identify prospects.
Many advanced technological tools, including reservoir simulators and 3-D seismic are available to all companies attempting to identify and evaluate conventional prospects. But the costs can be difficult to justify for smaller companies with tight pre-spud budgets.
In order to stay competitive, many smaller companies and operators are leveraging ever-expanding oil and gas databases to obtain information. These companies are using analytics to guide prospect generation. The most successful among them are those that are willing to think progressively about generating prospects.
Enhancing Existing Assets
While major oil and gas players are largely focused on increasing proven reserves, smaller independents are utilizing big data to optimize their actively producing assets.
For instance, data integration can allow companies to discover untapped horizons, identify potential infill well locations and optimize production of existing wells.
By applying analytics to existing assets, small companies can add value to their current production portfolio without exposing themselves to the costs and risks associated with identifying new prospects.
One of the unwritten stories of the unconventional reservoir boom is the future impact of production from uphole reservoirs that are currently kept under lease by horizontal production from primary target reservoirs (Eagle Ford, Bakken etc.).
A well-known large independent in the Eagle Ford trend has produced over 3 million barrels of oil and over 2.5 BCF of gas from 9 wells at about 8000ft in the Lower Wilcox formation.
Well production profiles show very little decline,
Monthly production profile chart showing very little decline.
and the distribution of calculated EURs shows a median value of over 750,000 barrels of oil per well.
Chart showing calculated EUR of 9 Wilcox field wells.
Total projected production from this small 1200 acre field is projected to be nearly 10 million barrels. Numbers like these hint at the untapped uphole potential for thousands of wells in these unconventional resource plays.
Given the very low rate of decline it’s likely that this conventional field will be producing long enough to leverage expected upward trends in wellhead oil and gas prices, even if that takes several years to materialize.
Monitoring Unconventional Activity
The shale oil and gas boom has also ushered in an era of elevated acreage prices. To avoid unnecessary acreage price increases when leasing for conventional development, companies must be aware of ever-broadening unconventional resource plays.
Increased data availability and advanced analytics have leveled the playing field in this regard. Even small companies are now able to anticipate the generation and expansion of new or underdeveloped unconventional resource plays.
Before committing to develop a conventional reservoir, companies should fully evaluate unconventional resource projections and the stage of unconventional resource development in the area.
This not only ensures that small companies are ahead of the curve, but it also can lead to added value for acreage that will eventually be held by production from conventional reservoirs.
The Oakland A’s of the Industry
As you can see, the oil and gas data revolution is providing an array of benefits to both conventional and unconventional producers.
Organizations of all sizes are now taking advantage of the era of big data in an effort to maximize company resources such as time, capital and talent.
By embracing the “compete with analytics” philosophy, smaller oil and gas producers are more equipped to swing for the fences, instead of relying on a small ball agenda for success.
So what do you think? Who will emerge as the Oakland A’s – or even the Boston Red Sox – of the oil and natural gas industry? Please leave a comment below.
Maximize Production with DI Analytics
Discover how you can drastically decrease risk and quickly, accurately and confidently make decisions with deep data-driven analytics based on the industry’s top unconventional operators.
UPDATED: April 11, 2017
The headlines continue to highlight positive developments by operators in the SCOOP/STACK plays in Oklahoma. But who is participating in the production streams BESIDES the operator? What non-operated interests or overriding royalty interests are participating right alongside the operator?
Or who was the initial grantee actually leasing for?
We’re lifting the curtain with the release of assignments in the SCOOP/STACK—in a big way!
Here’s what we’ve released..
Find out what’s been assigned—and what’s not been assigned…yet. Create AOIs around the areas that you want to watch for future opportunities, and do it with this level of detail.
Not only can our customers view assignments online within Drillinginfo, they can also create a leasing report in Drillinginfo for areas that they’re interested in. An example is this report on Kingfisher County, OK (STACK play) which shows 1 of 11 new leases taken as recently as 3/15/2017.
Use this tab in Drillinginfo to start creating custom reports.
Combining customized leasing reports with the power of our DI SCOOP/STACK play assessments is a powerful enhancement to operators who want to unlock current opportunities in these plays.
On November 16, 1907, Oklahoma became the 46th state to enter the Union. About a decade before that, in the then Indian Territory, Miss Jenni Cass dropped a “go devil” detonating device downhole and The Nellie Johnson no. 1 well became the first commercially viable oil well in the Territory. Fast forward to July of 2015 and we find the State of Oklahoma contributing the 6th most crude oil and 3rd most natural gas in the country. Not only is Oklahoma therefore in a combined 5th place in terms of energy resource production, it is also the home to the Cushing hub, where orders for West Texas Intermediate (WTI) oil futures are settled for the New York Mercantile Exchange.
Much of the news that comes out of Oklahoma lately centers around the disposal water quake controversy, and relative financial health of a few of the very large operators who are headquartered there. The recent selection of Paul Ryan as Speaker of the House has an interesting Oklahoma angle given that his wife Janna Little Ryan’s family has a rich Oklahoma political history. (Their family dogs are Boomer and Sooner).
Of particular interest to me is that when we look at a current heat map of permitting activity for the past 30 days, coupled with current active rigs, we clearly see that Oklahoma, particularly the Woodford Shale play in the Anadarko basin, is one of the nation’s bright spots.
Image Source: Drillinginfo Activity Maps
The SCOOP and The STACK
We’ve written about the South Central Oklahoma Oil Province, or SCOOP, before and how it’s exciting because it tends to be a little more liquids-rich. Operators, such as Magnolia, continue to expand their drilling plan for the play.
The competitive (because of geography and branding more so than geology) Sooner Trend Anadarko Basin Canadian and Kingfisher Counties, or STACK play has started to get a lot of interest lately, also due to its potential for liquids. STACK operator Newfield Exploration is one of the best-performing stocks in the S&P 500 this year.
In a presentation earlier this year, another STACK devotee, Felix Energy, talked about the performance they have been getting from applying new technology to the play area. 3 things caught my eye in this presentation:
- No produced formation water – they’re drilling for hydrocarbons and not having to deal with water disposal (!)
- Horizontal redevelopment with modern stimulations has yielded tremendous economic results – New horizontal wells 50x original vertical wells (!)
- Proponent of Slick Water proppant, and in 2015 using up to 2000#/ft (!)
The Woodford Shale and Hunton Group and the more recently targeted Springer Shale span from the late Ordovician into the Mississippian in geologic age.
Image Source: Drillinginfo South-Central Oklahoma Basins Play Assessment materials
If we look at the last 90 days of rig counts by county in the Woodford Shale, we see a slight pullback in the clear leader Grady from 16 to 12 rigs, a slight contraction from 8 to 7 in Canadian County, and a nice rally in Blaine County from 3 to 8. The Other STACK County, Kingfisher, is riding in fourth place, having gained a rig over that time period.
Image Source: Drillinginfo Rig Analytics
Looking at that same time period in just SCOOP and STACK counties, and cross referencing the targeted formations, we see a clear preference for the deeper Woodford and Hunton formations.
Image Source: Drillinginfo Rig Analytics
Woodford Shale New Production Capacity
On November 12, Drillinginfo will release its latest DI Index of New Production Capacity (NPC), which couples rig activity with active permits, compares the new wells’ performance with comparable wells, and creates an estimate for the capacity that will be brought online from that well in the next few months. This next image compares the NPC for Woodford Shale counties from October’s activity.
Image Source: Drillinginfo Basin-Level NPC reports
The amount of natural gas capacity coming online from the more easterly Hughes and Pittsburgh Counties is certainly striking, all the more so given that there are only 8 rigs generally running around the two. Just more evidence about how much more efficient the gas producers are getting at their game.
Next, Two of the top Five counties on the chart are Canadian and Kingfisher (and the final top fiver is neighbor Blaine), further reinforcing the current investment (and potential results) of the STACK play. And then, also with respectable numbers, Stephens, Grady, Garvin, and Carter show how the heart of the SCOOP is performing.
What do you think? Leave a comment below.
In the current oil-price environment we have all seen the tremendous decline in the number of active rigs across the country, in part led by steep attrition in the far-from-market Bakken and the less bountiful non-core acreage in the Eagle Ford. But there have been a few play areas that, though they have certainly suffered from the downturn, have kept activity levels up better than the national norm.
Previously we have discussed Oklahoma, led by its STACK and SCOOP; the Permian Basin’s Midland and Delaware basins, and recently the Utica Shale in Ohio.
But there is one play that pops up in a lot of operator presentations and analysis and news that we haven’t touched on recently, the mighty Niobrara, and in particular the oil rich donut of acreage in Weld County, CO.
The rock is always the most important factor, so let’s start there. I asked one of the geologist’s upstairs (Tiffany Guiltinan) to send me some info on what their team has been working on in Weld County. This first image breaks down the different tops that the team has identified and picked throughout the play area (the Chalks and the Marls, etc.), and also the resulting zones (Niobrara A, B, C, Fort Hays, etc.). On the right is an example of the impact faulting can have on a section – in this case the Fort Hays limestone has been faulted out in the second log from the right. She wasn’t sure if that was interesting or not, but I thought it was.
She also sent me a few charts related to the work the team has been doing with corroborating directional surveys to the different zones.
The upper left chart shows that the Niobrara B (with 43%) and C (with 23%) are clearly the most popular landing zones. The lower left shows that two thirds of Weld County horizontals are using a toe-down trajectory (more on that later). Upper right shows that most wells have a horizontal length around 4000-4500 ft, and lower right shows that most wells are going north/south or east/west.
If you want a little more background on the geology of the Niobrara, you can refer to Tiffany’s excellent post on the Smoky Hill Member, and Clint Barefoot’s The Niobrara Shale Formation – From Idea to Action in 10 Minutes.
Weld County Production and Drilling
Before we go too much further, lets add a little geography to mix, so we know where we are. For wells that have been brought on line in the past 5 years in Weld County, we see the donut-ring of oil production surrounding the donut-hole gas production in the southwest part of the county.
And looking at the same area, with active permits, we can see where some of the bigger name operators are focusing their activity.
One of the most striking parts of the permit image is the lines of permits that line up straight north/south or east/west. Hmmmm.
If we zoom into the area near Riverside Reservoir in the middle of the map, on the left we see when the permits go north/south, the wells go east west, and then when we overlay our (new) landtrac lease outlines, everything becomes clear. Since Colorado lines up their mineral rights in a PLSS system, lining up your wells along one edge and drilling to the other edge makes total sense.
The Heel and The Toe
I said I would get back to toe-up vs. toe-down trajectory. Consider the following well.
This is a well from that region near Riverside Reservoir. The red line represents the directional survey of the well as ingested and QCed by our data team. The colored areas represent the limits of the various zones as picked and QCed by our team of geologists. We determined the “heel” by selecting the point at which the well achieves an 80 degree from vertical in the survey (the blue point on the left), and the “toe” is the end of the well (the blue dot on the right). So in this case the toe is lower than the heel, whereas had we used, say, 88 or 89 degrees the toe might actually be higher and therefore “toe-up.” Also of interest is the fact that in this case the geological stack of formations is trending downwards , which means the hydrocarbons from the toe are going to be from the top part of the formation (in this case the Niobrara C), while nearer the heal they will be from the middle of the formation. Oh, also this well is drilled at an average azimuth of 88.94 degrees, meaning it is going from the west to the east.
Weld County Rig Activity
Speaking of toes, perhaps we can see a little bit of an upturn at the toe of this chart of rig activity in Weld County?
On the left we see the larger class rigs, capable of making the turns and keeping on schedule, have come to dominate the landscape, and on the right we see that, as expected, PDC, Whiting, Noble and Anadarko have taken over most of the action.
What do you think? Leave a comment below.
The oil and gas industry has always had to adapt to changing market conditions through supply change improvements, to the point of beckoning a factory style approach to resource play development. There is a clear correlation between adaptation or innovation and success in growing revenues across any industry.
Optimizing oil field development is planning for the long term while making/saving money in the short term and innovations such as multi-stage fracking, injection methods, horizontal well drilling, and pad drilling support those efforts.
The whole concept as it relates to the oil and gas industry has its challenges, but you can go a long way until you have to figure out how to handle the geologic (raw material supply) risk and optimizing the engineering to exploit the potential raw environment.
To start, let’s compare with a classic factory model standard. From Industry Week this interesting article highlights the top 5 factors optimizing complex manufacturing operations.
- Take advantage of revenue opportunities
- Tuning up operation and processes optimization
- Utilize ERP across the enterprise
- Finding harmony among diverse applications
- Coming to grips with complexity
In a nutshell, metrics driven and collaborative planning support harmony across diverse applications and information flow in order to build insightful critical business decisions. Dealing with change such as market shifts, supply chain interruption, regulatory changes, and competition are ingredients to a successful operation.
As a business, and particularly in the oil and gas business, taking advantage of revenue opportunities, and tuning operations and processes, can be accomplished through decision support tools. ERP is defined as an integrated view of core business processes, often in real-time, using common databases, where ERP systems track business resources. That is another can of worms to discuss on another occasion.
Focus on the last two items – complexity and harmony among diverse applications – in the context of an integrated geologic and engineering model.
You need to assimilate geologic and engineer data, manage model uncertainties, optimize well placement, and the number and density of wells. Manage a drilling schedule – calculate kick off, depth, inclination, azimuth, dog leg severity, anti-collision risk. Optimize completions and well operations such as pressures, casing, and flow rates, and go on to solve the inverse problem of history matching to make sure you understand the impact of your work.
Layer in subsurface constraints such as porosity, permeability, depth to pay, fracture half length, depletion and anticipated recovery rates, stacked pay opportunities and surface constraints such as lease, environmental and urban boundaries and regulatory and environmental requirements. An efficient operation can profoundly impact the long term productivity and profitability for a field.
In areas where hydraulic fracturing is heavy, a dense web of roads, pipelines, and well pads provide ample opportunities to optimize your development strategy. (Photo: Simon Fraser University/Flickr)
I was sitting with a colleague the other day where we were exploring ideas around how do we know why a particular formation /reservoir stopped performing and if shutting in a series of wells in a field drastically increased water production and decreased oil production. Was it the drawdown, , interference, field pressure management, geologic factors such as permeability and a possible stratigraphic influence? You can say “so what” to any number of scientific theories, until you use a data driven methodology to reach a conclusion. DI Transform is a platform that can bring harmony in a complex environment.
The DI Transform well interference workflow brings diverse data together to optimize well spacing while predicting future production and understanding depletion. Uncertainty around well density and how your field plan could impact future and past production in the context of geoscience information is accomplished in one application.
Scan wells in your field, inspect interference well pairs, calculate pre and post interference production volumes with the use of time lapse visualization, cross plots and analysis windows
The advanced well pair analyses tool affords rapid data scrutiny over an entire field; an activity that would normally take weeks or months collapses into hours or days. In this example above, a portion of the Montney field (Northeast British Columbia, Canada) interference workflow is used within a multivariate analysis incorporating completion data, and production interference in order to statistically uncover optimum well spacing.
Design a standard pad template based on engineering and geologic analyses, use surface and subsurface restrictions and anti-collision tools to build your field plan
Once you have established optimal density in terms of production and geology you can take it a step further from a field perspective. Drillinginfo‘s Pad and Field Planning workflow was designed in partnership with our customers (one of them from Canada!) with an eye toward bringing geoscientists and engineers into one space. Field planners can use the same tool and data environment to build consistent and standard well pads with factory precision. As in the above Montney example, an optimum spacing was established to construct a multi- level standard well pad that can minimize ecological impact at the surface and enable surface engineering efforts.
In the spirit of supply chain improvement and building better precision, landing in your target zone is critical to the success of your field development plan. Target zones can be optimized for a geologic zone, you may want to keep a specific standoff from the bottom or top of the formation, or stay away from water bearing strata. Those goals may differ depending on your production strategy – steaming, fracking, pump and flow rate targets. Understand your results and compare the performance of your target plan and have the tools to apply in engineering, the earth model and process improvement.
A rendering of the cross section along the wellbore path shows the lateral distance of the wellbore within its corresponding reservoir zone
Tough times call for discipline, technical expertise and long and short term planning to bring an operation to success and victory. The ability to mitigate risk in a quantitative way and optimize the engineering to exploit the potential raw environment is here today.
What do you think? Leave a comment below.
Robert Frost’s poem “The Road Not Taken” concludes with the lines:
“two roads diverged in a wood and I—I took the one less travelled by, and that has made all the difference.”
Having just returned from my Dartmouth Class of ’71 45th reunion I suppose I can be forgiven for tapping into Frost’s poetry, given his connection to my alma mater.
But this is where Decline Curve Analysis algorithms are these days—at a fork in the road, and the one you choose to evaluate your significant acquisition or divestiture candidates will make “all the difference”.
Whether you are a completions engineer who is trying to gauge the outcomes of new completion techniques, or you are reporting to your board of directors with forecasts of the cash flow of operated properties, getting your numbers right has never been more important in these times of tight margins.
With high initial decline rates and maybe long term transient flow characteristics, unconventional decline curve analysis can be especially challenging. Do it too early and you risk “pessimizing” your EURs with algorithmic assumptions that are too pessimistic about future behavior.
Use an inappropriate algorithm—for example exponential vs hyperbolic—and your answers will be widely different. For the lease below, the difference is just over 440,000 BO and 1.7 BCF of EUR. That represents an unacceptable error range of production estimation.
Our new approach within Production workspace has been to introduce probabilistic estimation into decline curve analysis, so that the algorithm we use is sensitive to outliers in the data and doesn’t rely on brute force curve fitting to a collection of points. Moreover, it calculates the probability of any EUR value actually being correct (P10,P50,P90).
Here’s the type curve for Delaware Basin Bone Springs wells that have produced at least 100,000 BO.
It would imply that production in the play is reasonably predictable.
But Mother Nature is never this predictable. This well is a challenge to traditional decline curve analysis
By pre-selecting the Logistic Growth Model algorithm option, The Decline Curve analysis in Production Workspace computes bin volume estimates, assigns them a probability, and re-iteratively calculates fresh inputs into the algorithm to arrive at this:
…with these P10-P90 probabilistic reserves.
An “out-of-the box” (read: Black Box) algorithm from a third party calculates the EUR for this well at nearly 1,200,000 BO-1,770,000 (depending on method), which is nearly 2x-3X the P90 from Production Workspace Decline Curve analysis.
The point is this: No matter what software or consultant you use to estimate EURs, it’s essential to know the underlying algorithmic models that are embedded in the software. It’s even more important to know, if you can, their error ranges.
Taking the wrong road at the fork can, at best, get you lost.
At worst, it can lead to ruin…
What do you think? Leave a comment below.
When Drillinginfo first started releasing counts of the Drilled but Uncompleted wells (DUCs) in the U.S., I immediately was questioned on how to interpret the results. Everyone had a different DUC well definition, depending on what they actually wanted to evaluate. So let me suggest some terminology to clarify what we are talking about…
DUC well: At Drillinginfo, we begin our analysis with the literal definition: a well that has been drilled and has not yet been completed. As of June 23, we had approximately 6,100 DUC wells in the 14 states where we track DUC wells, excluding new wells drilled in the month of June, as shown in Figure 1.
The chart shows the DUC well count based on the month when the well was drilled, and the high number of American DUCs in recent months indicate normal inventory in the process of being completed.
While the total DUC count is useful to track activity levels and forecast potential production, examining DUCS by vintage refines the DUC count into relevant subsets. Let’s use the Eagle Ford as an example, where we have 586 total DUCs as of June 23, as shown in Figure 2.
Similar to Figure 1, this chart shows higher level of DUC wells in more recent months, reflecting what we’ll refer to as work-in-process inventory (WIP). This is the portion of DUC wells in the normal lag time where the drilling has finished but completion activity hasn’t yet begun, or where a completion might have been finished but the associated filings have not yet been published nor has production been reported. This “time lag” varies by state based on different regulatory requirements, but simply scanning the chart indicates a step-change in DUCs from December 2015 to present. If we make a general assumption that wells drilled in the last six months are part of WIP inventory, we have approximately 248 wells in the Eagle Ford that we would expect to move from drilled to completed status on a normal schedule, as illustrated in Figure 3.
The chart shows the number of wells in the month they were drilled and the county where they are located. Not surprisingly, the most active counties for recent drilling are Karnes (green) and Dewitt (dark pink) in the core of the play.
Deferred completions: Many times when people ask about the DUC count, they really want to know the number of “deferred completions”, where drilling finished more than six months ago, and we still have no evidence of any completion or production activity. This may occur because a company is waiting for pipeline infrastructure or capacity, or because of an intentional delay waiting for better oil or gas prices. When I compute deferred completions, I typically begin counting DUCs from approximately October 2014, where there was an increase in DUCs coinciding with a significant decline in oil price, up to the WIP inventory period. Continuing with our example, we have 296 deferred completions in the Eagle Ford during October 2014 through November 2015 as shown in Figure 4.
When and if these will come online will depend primarily on oil prices, and we can map them to see locations relative to the core, estimate future production based on offset wells, and perform a single well economics to determine when completing these may be economic.
What about DUC wells drilled prior to October 2014? This may be included in deferred completions, but I often refer to these as “dead DUCs.” If wells were not completed when oil was $90-$100, there is a good chance these will never be completed. We have 42 in the Eagle Ford during the period March 2014 through September 2014, as shown in Figure 5.
Classifying the 586 total Eagle Ford DUCs into work-in-process (248 wells), deferred completions (296 wells) and dead DUCs (42 wells) isolates relevant portions of the DUC inventory to enable comparative analyses and start to evaluate changes in these counts over time. For example, two weeks ago, there were 315 deferred completion DUCs, so operators have completed 19 of those wells.
 Our approach utilizes rig tracking to identify wells drilled, and then queries permit types, completion records filed at the state agencies, Frac Focus records, and well status filings to identify DUCs. We have a whitepaper available upon request that further details the methodology.
 These wells were finished drilling in October, before prices fell, but the product would not be brought online until November or later, at the lower oil price.
What do you think? Leave a comment below.