Operations America

With WTI oil prices rallying 15% in the first month of 2021 and late-winter cold lifting Henry Hub back toward $3 MMBtu by early February, market momentum is clearly swinging in a positive direction. While the bulls may not be off and running just yet, with a growing number of analysts projecting further price strengthening and rig and frac spread counts increasing by the week, the bulls are beginning to gather in the oil and gas pen again.

With improving market fundamentals framing the backdrop, AOGR thought it would be an opportune time to assess the way forward through the eyes of three independents that are setting a course for the future by returning back to where it all began for U.S. shale plays: the Austin Chalk, Barnett and Permian Basin.

In South Texas, EOG is developing a large new field discovery targeting the Eagle Ford and Austin Chalk, the grandaddy of the modern resource plays concept. In North Texas, KBV Corp. is implementing a technology-driven optimization program across the very Barnett acreage where shale gas was first commercialized. In West Texas, DoublePoint is running a multi-rig program targeting stacked intervals, including the Spraberry, the Permian’s original unconventional play. Meanwhile, data and technology providers such as TGS are helping operators gain new insights and capture upside potential on their foundational assets, whether new discoveries or infill development opportunities.

To get an update on the status of these projects and preview what’s ahead, AOGR turned to Ken Boedeker, executive vice president, exploration and production at EOG Resources; Eric Jacobsen, chief operating officer at BKV Corp.; Cody Campbell, co-founder and co-chief executive officer at Double Eagle; and Matt Mayer, product owner at TGS.

EOG Adds Dorado Dry Gas To Premium Play Portfolio

Q: Let’s begin with an overview of the Dorado discovery. Please synopsize the sub-basin’s geographical location, geology and production characteristics, and EOG’s acreage position. How many Dorado wells have been drilled to date, and how many drilling locations have been identified targeting the Austin Chalk and Eagle Ford (or other prospective intervals)? What are the total estimated potential recoverable reserves?

BOEDEKER: We are excited about this major new natural gas discovery in the western Gulf Coast Basin. It is the latest example of EOG’s sustainable business model of organic exploration-driven resource expansion.

The Austin Chalk is what we call a hybrid play. That is, it shares characteristics of unconventional and conventional reservoirs. We have found that hybrid plays react very well to our horizontal completions technology.

Our current 163,000-net acre position in Webb County, Tx., is a combination of legacy acreage and new acreage captured through low-cost, organic leasing, trades, and a bolt-on property acquisition. We believe our position covers the majority of the sweet spot of the play.

We completed our first two wells in Dorado in January 2019, targeting the Austin Chalk and the Eagle Ford. To further delineate the play and collect more data, we completed 15 more wells over the remainder of 2019.

We have identified an initial resource potential of 21 trillion cubic feet net to EOG in the Austin Chalk and lower and upper Eagle Ford formations: 9.5 Tcf in the Austin Chalk and 11.5 Tcf in the Eagle Ford. Dorado adds 1,250 net locations on fee acreage to our premium inventory with 530 of those from the Austin Chalk and 720 from the Eagle Ford.

Q: Dorado is located in an area with a 100-year production history. As EOG has described it, Dorado was “generated from the bottom up” as an outcome of its regional technical analysis of the Austin Chalk trend. Looking at the genesis of the play, how was the Dorado sub-basin identified? Walk us through its evolution from an exploration concept to ultimately getting the green light for development.

BOEDEKER: We first identified the potential of the Austin Chalk formation as an oil play on top of our Eagle Ford footprint back in 2016. We have since completed about 100 gross Austin Chalk oil wells in that area, capturing 59 million barrels of oil equivalent of reserve potential net to EOG.

Shortly following that discovery, we began evaluating the Austin Chalk formation in the Gulf Coast basin and identified its potential as a dry natural gas play in Webb County. We drilled 17 wells in 2019. We paused our drilling activity during 2020 to evaluate both the production results and the significant amount of technical data we collected from cores, petrophysical logs and 3-D seismic surveys. This data, including a year’s worth of production history from our drilled wells, has generated a robust reservoir model, giving us confidence in our resource estimates and projections for well performance.

Q: What are the production profiles and estimated EURs of the wells completed thus far? What are the estimated break-even costs across the play? How do Dorado’s dry gas economics measure up in the investment portfolio against EOG’s “premium” tight oil plays? (EOG defines premium inventory as those prospects that generate at least a 30% direct after-tax rate of return at a $40 flat oil price or $2.50 flat gas price).

BOEDEKER: With a break-even cost of less than $1.25 per Mcf, we believe this play represents the lowest cost supply of natural gas in the United States. At Henry Hub prices of $2.50 per Mcf, Dorado competes directly with our premium oil plays. We are leveraging our proprietary knowledge built from prior plays to move quickly down the cost curve with our initial development. We currently estimate a finding cost of $0.39 per Mcf in the Austin Chalk and $0.41 per Mcf in the Eagle Ford.

We have drilled 17 wells in the Dorado play since January 2019, including five wells targeting the Austin Chalk and 12 wells targeting the Upper and Lower Eagle Ford. The five initial Austin Chalk wells produced an average of 3.5 Bcf of natural gas per well in the first year of production, with an average lateral length of 6,600 feet per well. A typical Austin Chalk well is expected to recover 22 Bcf of natural gas, or 18 Bcf net after royalty, from a 9,000-foot lateral at a targeted well cost of $7.0 million per well.

The first 12 wells targeting the Eagle Ford produced an average of 2.8 Bcf of natural gas per well in the first year of production, with an average lateral length of 7,700 feet per well. A typical Eagle Ford well is expected to recover 19 Bcf of natural gas, or 16 Bcf net after royalty, from a 9,000-foot lateral at a targeted well cost of $6.5 million per well.

This play is a textbook example of how our exploration program is focused on adding to the top of our premium well inventory, elevating the overall quality of our assets.

Q: How many wells does EOG plan to drill in the play in 2021? What kind of drilling and completion designs is EOG using on these wells in terms of lateral lengths, stage counts, perforation strategy, proppant density, etc.? How is EOG applying the knowledge and skillsets acquired in its past experiences in the Eagle Ford and Austin Chalk play areas to optimize the performance of Dorado wells?

BOEDEKER: We will evaluate the capital allocation to this South Texas gas play each year based on market conditions. In 2021, our preliminary plan is to turn about 15 net wells to sales with initial development targeting the Austin Chalk.

Eagle Ford development, where we are expecting lower drilling and completion costs, will follow. The Eagle Ford utilizes a lower-cost wellbore design optimized to a more forgiving drilling environment compared with the Austin Chalk. In addition, we can leverage water and gas gathering infrastructure put in place for the Austin Chalk.

The benefit of our decentralized organization is that we essentially have eight smaller exploration and production companies that function as independent incubators of innovation. With each new discovery, the velocity of drilling and completion innovations to lower capital costs and improve well productivity increases. In addition, with each new discovery, our production facility design and automation of field operations reduces operating costs and lowers emissions intensity.

Dorado certainly benefits from our past experience in the Eagle Ford and Austin Chalk, but more importantly, it benefits from more than 15 years of institutional knowledge in horizontal, unconventional development that shortens the learning curve throughout exploration, development and operations.

Q: What is the long-term development plan? Tell us about infrastructure in the area supporting Dorado’s development and targeted production volumes? Is there ready pipeline takeaway capacity out of the sub-basin? How is EOG building out the capabilities to facilitate its water, emissions and other ESG management objectives for the project?

BOEDEKER: Dorado fits everything we are looking for in a new play to add to the company’s premium assets. It upgrades our portfolio and gives us a lot of optionality in the future to switch capital between types of plays as commodity prices vary.

Combined with EOG’s low operating costs and advantaged market position located close to a number of major sales hubs in South Texas, access to pipelines to Mexico and several LNG export terminals, Dorado is in an ideal position to supply low-cost natural gas into markets with long-term growth potential.

Dorado is dry gas with close proximity to multiple markets. Therefore, we expect Dorado’s gas will have a lower carbon footprint than most other onshore gas plays in the United States.

In addition, the recently formed Sustainable Power Group we introduced last quarter is leveraging companywide expertise to build out an operationally efficient and low-emissions field. As we expand development of Dorado into a core asset, we expect it will help lower EOG’s companywide emissions intensity rate.

Growth Agenda In Action

Q: BKV Corporation was established in 2015, and while the vast majority of its peers was focusing on oil, it was quietly becoming one of the top 20 U.S. natural gas producers. The company is obviously a big believer in gas. What are the drivers behind the corporate commitment to natural gas? Since inception, the company has grown through a series of seven acquisitions totaling $1.3 billion. Why has it elected to build its operational base in the Marcellus and Barnett shales?

JACOBSEN: We share a belief at BKV that natural gas is the fuel of the future. It is of critical importance today to meeting the world’s energy needs, and we see the demand for natural gas building with glimmers of the world’s emergence from the COVID-19 devastation. Natural gas is abundant, affordable, reliable, safe to develop, and it transforms communities and lifts people out of poverty. All these reasons, in addition to natural gas being a clean and environmentally responsible energy source, are why we believe that natural gas is the fuel of choice and that demand for gas supplies will grow in the coming years.

Our vision is to be a dominant U.S. unconventional natural gas-weighted production company, delivering superior risk-adjusted returns to shareholders. Our approach is to scale, apply technology and automation, optimize assets, operate at very low cost and highly competitive margins, generate a lot of cash, and be a distinct leader in the ESG space. Several unconventional gas-weighted basins in North America enable us to meet all of these criteria, and with our approach, will ultimately enable us to deliver higher profit-per-molecule than peers in the industry.

The Barnett is the most mature of the U.S. unconventional plays. The very low-decline, large producing base with well-established infrastructure and access to great markets are all attractive aspects. We see ample opportunity to apply automation, inject some innovative approaches and optimize the asset. There are also some attractive, high-return development opportunities in both our Barnett and Marcellus acreage when market conditions are ripe.

Importantly, there is considerable opportunity to scale our asset base in the Barnett as well as in the Marcellus, and we will continue to seek acquiring high-quality, right-priced prospects in both basins. On that note, regarding growth through mergers and acquisitions, we are very pleased to have recently announced an investment partnership with Oaktree alongside our principal investor and foundational backer, Banpu North America Corporation. Oaktree is a highly reputable institutional investor, and it has invested $100 million in BKV, with a commitment of $600 million in additional funding toward mutually agreed future opportunities.

Q: On Oct. 1, BKV closed on a $570-million acquisition of Devon Energy Corp.’s Barnett Shale assets, making it the largest producer in the play. The Barnett is, of course, where the shale revolution began more than two decades ago. Why the Barnett and why now? How does purchasing this legacy position and its estimated 4 trillion cubic feet equivalent of proved reserves complement BKV’s portfolio and set it up for the future? How does the Barnett formation’s liquids-rich production stream enhance production economics?

JACOBSEN: Our acquisition in the Barnett demonstrates BKV’s growth agenda in action and delivers on our core strategy of becoming a dominant U.S. unconventional natural gas-weighted operating company that delivers superior risk-adjusted returns to investors while being a force of good to society. The Barnett is where the shale revolution began. When we became aware that Devon wanted to divest of this asset, we went to work. We had previously recognized the advantages of the Barnett Shale, and in particular, Devon’s basin-leading position. Mitchell Energy had pioneered the asset beginning in the early 1950s, and started commercial development of the Barnett formation in the late 1990s before Devon acquired the company in 2001. The rock quality across the asset is among the very best in the basin.

When we layered on the other benefits of this play–sizeable, low-decline producing base, existing infrastructure, and the business-forward and protective, yet reasonable, regulatory environment in Texas–we were excited to jump in. Entering the Barnett with such a significant footprint not only diversifies our company portfolio, but with our focus on innovation and technology, we are in great shape to maximize our base production and execute on the rich opportunity set this asset offers.

The balance of liquids-rich and dry gas–approximately two-thirds and one-third of the production volumes, respectively–affords us the ability to access the natural gas liquids pricing upsides and balance our commodity mix a bit across the company portfolio. The NGL component may prove a very nice cash generator for us in the coming period, given reasonably sustained demand coupled with the drop in rich, associated gas production in oily basins.

Q: The Barnett deal encompasses 320,000 gross acres and 4,200 producing wells. At the time the deal was announced, net production from the properties averaged 600 MMcfe/d. What kind of upside does BKV see in the play? How do you plan to optimize production over time?

JACOBSEN: After taking over operatorship of the asset on Oct. 1, we commenced multiple production enhancement and cost-reduction efforts. We are really pleased with the results thus far, and have identified even more opportunities than we had initially anticipated. We will be scaling up those efforts throughout 2021.

As I mentioned, we are very focused on automation, implementing innovative ideas and applying new technology to optimize base production. We have demonstrated great success on all these fronts in our foundational Marcellus position and are now applying these and more in an even larger way in the Barnett. We are already executing some of this innovation on existing Barnett wells.

We applied our automation and technology path to Barnett wells by first programming, and then turning “on,” existing plunger controllers in an auto-control mode. From there, we are initiating another round of auto-control sophistication, seeking improved monitoring and rapid response to highly accurate predictive models and real-time variables alike. We also will be monitoring the field conditions as a whole, including midstream functionality and pressures, and making real-time adjustments or implementing strategic, longer-term projects to further optimize production and reserves recovery at industry-leading low costs.

The application of automation and technology enables quicker and lower-cost production responses to changing variables; allows for fieldwide, larger-scale monitoring and opportunity generation; and enables a continuous and machine learning cycle where outcomes can be applied rapidly.

Q: What are the development plans for the properties in 2021? Will you be drilling and completing new wells? How about the midstream infrastructure? Does BKV own gathering and processing infrastructure capacity in the Barnett?

JACOBSEN: As for drilling and completion development opportunities, we are further evaluating those and certainly like what we see on several fronts. For now, I’d say more on all of this later in 2021. We are assessing what worked well and what did not work as well in the past for Devon and other Barnett operators, evaluating the latest in drilling and completion technology, reviewing the subsurface in detail, and building our plan on the drilling and completions front.

At this point, our priorities and business strategy are to deliver the best margins, generate cash, and grow more through M&A and existing asset optimization than through the drill bit. Yet, we will be more than ready and capable to drill and complete some great rock in both of our basins when we see that the market conditions are ripe.

Building out the gathering, processing and pipeline capacity in the Barnett was a large piece of George Mitchell’s business model. It was also a large part of Devon’s Barnett model for many years, but Devon and CrossTex merged their midstream assets to form the EnLink MLP that eventually spun off from Devon entirely. None of these were a part of our Barnett acquisition and we do not currently own midstream assets in the Barnett.

Q: In its early days, the Barnett served as the field lab for the evolution of much of the science behind modern shale gas development. One of BKV’s core corporate values is “a strong focus on geoscience and engineering fundamentals.” How do you see that manifesting itself in the Barnett assets? What percentage of the producing wells are completed in the Barnett formation versus other intervals? How many are horizontal versus vertical?

JACOBSEN: With 4,200 wells and about 320,000 net acres, our Barnett asset is ideal to apply automation and big data. We have already automated about two-thirds of our wells producing on artificial lift, which is yielding solid production improvements. Our next steps include highly accurate predictive well performance tied to our automated well controllers and adjustments made through algorithmic inputs.

In addition, we have a robust team of seasoned engineers, geoscientists and operations experts who are applying innovative, lower-cost recompletion, restimulation, artificial lift and remedial well work techniques to the Barnett assets. We believe that there are abundant opportunities to up the overall recovery factor and generate very strong returns in this mature basin.

In terms of formations, 87% of our producing, operated wells are completed in the Barnett. Other producing formations include Bend Conglomerate, Caddo, Grant, Smithwick, and Strawn. The wells are split roughly 50/50 between vertical and horizontal. Of the 4,200 wells, a total of 3,095 wells are on artificial lift. Of those, 2,645 are on plunger lift, 370 on gas lift, and 80 are on rod pump.

Catalysts For Capital

Editor’s Note: Campbell’s comments were adapted from a panel discussion at the Independent Petroleum Association of America’s 2021 Private Capital Conference, held virtually in late January. AOGR gratefully acknowledges IPAA for permitting access to the conference presentations.

Q: Private equity backing from Apollo Global Management and Quantum Energy Partners has played a pivotal role in Double Eagle’s/DoublePoint’s evolution, particularly for organic acreage acquisitions. The company also maintains a reserves-based lending facility. Looking at the financial markets in general, what will it take for capital to return to the oil and gas sector?

CAMPBELL: There are several high-quality deals to be done and I think we are going to see some of them happen in the near future. Once a few good deals happen and capital providers start achieving strong returns by investing in the industry, others will move into the space. It is sort of a self-fulfilling positive feedback cycle. When people start to do good deals and make money, a FOMO (fear of missing out) factor will come into play. Once the run starts, it could be a really good one because valuations are really low right now and the fundamentals are actually really strong.

An additional potential catalyst is related to the astronomical valuations in the clean energy space. Many firms that historically invested heavily in the oil and gas world have shifted capital to alternative energy. At some point these valuations have to rationalize and correct to some extent. Once we see momentum abate in the energy transition space and some losses are taken, which I think is almost inevitable based on current valuations, we will likely see investors rotate back into our industry. This dynamic could become another catalyst for capital flowing back into upstream oil and gas.

The bottom line is, never underestimate the oil and gas industry and our ability to find more and more efficiencies. The high-quality upstream oil and gas companies are making good well-level returns right now, even in this price regime. The macro fundamentals are sound. Demand is there, and the supply picture is looking better and better for a continued upward run in crude. I am optimistic. I think the next 12-18 months could be a really fun time in the industry and I am looking forward to it.

Q: Let’s drill down a little deeper to look at both the debt and private equity markets. DoublePoint announced last spring an increase in its syndicated reserves-based credit facility using both private equity and bank funds. How do you summarize the availability of investment capital for the upstream sector? What criteria are investors looking for?

CAMPBELL: As it stands right now, capital is available if you have a solid asset in the right basin, have existing cash flow, and have a good operational track record. The debt markets are strong right now. We recently completed a successful bond offering, which, to some extent, proved that good companies with good assets can get capital. But investors need to see free cash flow. If you are trying to finance a big outspend, good luck!

There has already been, and will continue to be, a pretty significant paradigm shift with respect to the type of assets that private equity will invest in and build. The acquisition and divestiture market demands assets with cash flow and high quality inventory behind it. If you do not have both of those things, you are not going to be able to monetize your asset.

It used to be that you could back a team, put some acreage together in an emerging play, drill a few wells to prove the position geologically, and then sell it. That is no longer the case. Buyers in this market need a significant flowing production and high-quality inventory for future development. Private equity must be willing to build out infrastructure, get a development going, and then mature a production profile and cash flow.

There is a definitely an opportunity for private equity, but it will be more focused on building companies rather than building assets. Also, private equity providers will probably need a longer hold period, which is not a comfortable thing for some funds. For others, it is fine. Some private equity has a slant toward more development and is comfortable with the operational side of the business, but others are not.

The lower-cost-of-capital players could find a spot in the industry as well. Our onshore basins have become more de-risked and a lot of the operational problems that we were encountering a few years ago have been solved. So, there is not much guess work as to what to expect from a development program in the proven basins. I think there is an opportunity here for the lower-risk sources of capital.

Q: What kind of environment to do you see for operators seeking to expand through M&A? What will it take for buyers and sellers to come together to get deals done? What will capital backers value more, good assets or good management?

CAMPBELL: The M&A market is not necessarily driven by a lack of buyers, but by the financial side of the market. Whether on the credit side or the private equity side, oil and gas investors want to see free cash flow. The story that was pitched for many years was that shale companies were making good returns, re-investing capital, and were only a year or two away from generating free cash flow. For too long, the industry just did not get to the places it promised. Well, finally the industry has matured to the point where most companies that have good assets are well positioned and are free cash flow positive. Their balance sheets are in good shape, leverage is low, and they are making better well-level returns than they ever have. The fundamentals are finally there.

But the investors that lost money in the process of the shale industry maturation now demand discipline. Again, they are focused more on businesses and less on the assets, so to speak. They want to see cash flow. Investors are not interested in proof-of-concept or early-stage development projects. They do not want to have to climb a production curve to get to free cash flow positivity.

On your second question: The quality of the operator definitely matters, but geology is the most important factor. You can have the best operations team in the world, but if you don’t have good rock, you aren’t going to be able to produce good returns.

Our industry has learned a huge amount about how to best develop shale, especially in the more delineated basins. The operational guesswork is largely behind us and the operators cooperate and collaborate well and share ideas. But there are some operators who are better than others, especially in terms of lease operating and capital costs.

Q: You have mentioned the need for cash flow and inventory to attract capital, and shifting investment criteria. On balance, how do these variables factor into the longer-term health of U.S. shale plays? How might policy changes in Washington impact the outlook?

CAMPBELL: Because of our industry’s current high level of capital discipline, it is probable that we have seen the peak of shale production for the next few years. People just are not drilling as much. We will have to wait and see what happens in the long term; I think the resource potential is still significant. The United States will continue to be a major player in hydrocarbon production, and that is great for this country. Imagine if we did not have shale production. Imagine what the global oil market would look like, and imagine where our country would be economically. We would be much worse off, and all of our industries, especially our manufacturing, would be less competitive. And if we did not have cheap energy to fuel the economic recovery from the pandemic, it would be a much tougher road for us. I believe the United States will maintain our significance in energy; it just makes common sense that we would. I am optimistic about the future of this industry and look forward to playing a part in it.

The public policy regime that is currently being implemented is bad for the country…bad for the American consumer, and bad for American industry. It is sad and unfortunate for this country that energy prices are going to increase and that people are going to lose jobs. That is tough and I hate to see it, but it probably will increase oil and gas prices over the near and medium terms. There really is not a part of the current policy regime that is not supportive of higher commodity prices and will probably be good for certain segments of the oil and gas industry, but there will certainly be some disruption.

Globally, exploration has been down for a while now and I do not see that changing anytime soon. At some point, the pipeline of new domestic onshore projects, and even international, are going to dry up. The world economy is going to say, “Where do we get the barrels we need?” They won’t be there. This is going to be happen because the investments in capital, time and effort, and technical expertise have not been happening.

Instead of investing in new exploration, companies have had to focus on quarterly cash returns. Some companies have inventories to sustain their drilling programs for years without new exploration, but the industry as a whole is going to need more inventory to continue producing the oil and gas that is demanded by the economy. Down the road there is going to be a need for new resources, and those projects are not going to be there for us as they have been in the past.

Technologies Drive Data Enhancement

Q: One of the hallmarks of shale plays is that they are located within legacy basins with histories of conventional development. Given all the vintage data and the new data acquired from unconventional reservoir development, how can this universe of information be analyzed to find new discoveries in and around established basins? What types of data and technical tools can optimize the drilling and development decision making process?

MAYER: Legacy basins are currently in the sweet spot of where data enhancement can really drive decision making to optimize development and growth. Newer processing techniques using machine learning and artificial intelligence can make use of these data-rich areas to enhance the often poorer quality of legacy data and combine disparate datasets to create insights and solutions.

The main thing missing from many contemporary machine learning and AI applications that keep them from being more widely trusted and adopted is a sufficiently large dataset to train the models. This turns out to be a perfect match for legacy basins, which have an overwhelming amount of data to train and validate results using blind tests from held-back datapoints. The exciting thing about these workflows is that each incremental step forward is compounding. For example, upscaling logs to include five major curves across the entire well interval not only makes that individual log more useful, but it also adds more data as an input to create larger-scale interpretations.

In petrophysical and log analysis, machine learning has been especially useful in upscaling legacy data quality. Missing log tracks or depth intervals can be reliably filled in using multivariate relational machine learning algorithms, which allows for better characterization of rock properties and creates standardized and complete datasets. Then, using a training dataset of geologist-picked tops, machine learning algorithms can be trained to efficiently pick equivalent tops for thousands of wells across the basin. These machine-learning-picked tops then can be used to create a unified basin stratigraphic model, which supports higher-level interpretations and analyses. Each step along the path creates new tools and solutions to solve problems ranging in scale from individual wells all the way up to conceptual understandings of a play.

Another area where machine learning has continued to enhance decision making is in cross-disciplinary geological and geophysical models. Seismic surveys always have been a highly valued tool in evaluating plays for potential exploration and development, but generating insightful knowledge is a heavily resource-intensive task that may not be suited to answer all relevant questions needed to make better development decisions. However, recent case studies have shown solid evidence that combining geophysical data with petrophysical data in a machine learning model can create unique interpretive solutions.

Machine learning seismic inversion methods have been shown to confidently predict properties such as p-impedance and density at a correlation of 0.88 and 0.70, respectively, providing results that are at or above the upper threshold for prediction from traditional inversion techniques. These methods can predict with higher accuracy, at a higher resolution, and faster than traditional inversion methods. Machine learning is also being used to identify patterns in seismic, such as notoriously hard-to-find salt structures in offshore settings. The practical implications of these workflows are better reservoir characterization to find higher-quality pay and more efficient completion designs.

Overall, the big new thing is creating tools that fuel better decision making and are more widely accessible to more key players. The major pieces required to create these tools include a vast inventory of G&G data in legacy basins and an innovative approach to processing using machine learning that results in outcomes that are far more valuable than the sum of their parts. We think these tools will allow for better decision making and resource allocation, which will really be the key driver in success for unconventional plays moving forward.

Q: In keeping, how can operators better evaluate and analyze their existing leaseholds in established resource plays to gain new perspectives on infill development and ultimately add upside value and recoverable reserves?

MAYER: In the current economic environment, unconventional plays require a precise balancing act of managing costs and highly informed decision making on where to most efficiently allocate resources. The days of true resource plays and mass indiscriminate development are, in all likelihood, behind us. In order to survive, operators will need to be laser-focused on which assets are most likely to yield a high return on investment. The good news is that insightful decision making is more accessible than ever, especially to smaller operators that may not have the staff or lead time that historically has been required to build full-scale geologic models and simulations.

One of the major barriers to effective infill development of existing assets is the uncertainty regarding the detrimental effects of well interference. This type of analysis can be done through full-scale models using precise completions, fracturing and monitoring data. But the real innovation is the growth of generalized visualization and interpretation modules that can perform the same analysis using more commonly available datasets in a fraction of the time. This is the type of interpretive data that big players have always had access to, so making it easier to generate and more broadly available helps to level the playing field in the decision making space.

Q: What does the data generally tell us about production performance over time in the major shale basins? Are we seeing distinctive trends regarding productivity and decline patterns? What do they imply about the way forward in these plays as commodity prices recover?

MAYER: One trend we are seeing develop at varying levels across multiple unconventional plays is simultaneous increases in well completion costs, initial production rates and decline rates. This has a tangible impact on project net present values, which place a higher value on quicker returns on investment, but also means that future gains in oil prices may be less effectively capitalized on by existing wells.

An unconventional play such as the Delaware Basin might be poised to take advantage of this new development for a couple of reasons. The biggest factor is that Permian plays tend to produce significantly higher volumes of water than many other unconventional plays, and as the common water disposal target formations are becoming overcharged, the price of water disposal is steadily increasing. If these newer trends shift more of the production to the first couple of months, effectively shortening the life of the well, then that also leaves less time necessary to produce and then dispose of higher water volumes.

Q: What about conventional reservoirs? Are there basins where conventional development has a strong economic rationale as prices continue to recover? Could we see an uptick in conventional exploration any time soon?

MAYER: Onshore U.S. conventional development is likely to continue to remain fairly close to its current trajectory. Unlike unconventional plays, where dynamic economic conditions could potentially open access to innumerable price-sensitive reserves, the driving limitation of conventional plays is diminishing reserves. However, many regional players who have carved out profitable niches in conventional reservoirs using a variety of techniques to enhance production, such as horizontal infill drilling in existing fields or EOR flood operations, will continue apace.

One development concept that may see an upside if economic conditions turn more favorable lies at the fringes between conventional and unconventional reservoirs. “Halo” plays, marginal areas of conventional plays that have been left undeveloped due to poor reservoir quality, can be more efficiently exploited now using various drilling and completion techniques learned from unconventional shale operations.

Two areas where we see a lot of potential for halo plays include the clastic reservoirs in the Powder River and Denver-Julesburg, which are both Cretaceous basins with similar characteristics and extensive development histories. The rich data history in these legacy basins will help to identify the most productive formations and facies. There potentially may be dozens of lower-quality paralic deposits surrounding historic fields in these basins that could develop into productive trends.

Another development concept that may play an increasing role moving forward is offshore conventional projects. While this would rely not only on favorable economic conditions but also on favorable regulatory and leasing conditions, some promising opportunities are still available in U.S. offshore areas. The Artic National Wildlife Refuge North Slope play has the potential to rival the Prudhoe Bay Field, and in state waters on the Gulf Coast, there are promising indications of an ultradeep play in the Wilcox that could lead to a huge discovery.