Unconventionals

We help clients optimize their businesses to capture the potential of tight gas, shale gas, and light tight oil.

Recent developments in unconventional energy have delivered huge technical gains, yet industry economics remain challenging. In an environment where improving efficiency and reducing costs are imperative, we help operators eliminate waste and variability, optimize material and resource planning, share data and best practices, and identify and capture opportunities as they emerge.

HOW WE WORK

We draw on our extensive industry knowledge, deep pool of experts, and decades of service to the energy sector to provide distinctive insights into topics such as:

  • achieving best-in-class performance in the speed, accuracy, and economics of drilling, completions, and field operations; optimizing equipment design for better subsurface access and reservoir production; and building lean, agile organizations to thrive in times of rapid change

  • understanding the strategic implications of supply, demand, and other macroeconomic factors; gaining insight into emerging market strategies; and developing portfolio strategies by stage of development

  • assessing midstream requirements, supply and flow shifts in differentials and netbacks, and producers’ decisions to optimize investment and ownership models throughout the life of lease

  • entering emerging basins and crafting novel operating models for new regions to take account of local economics, access requirements, and competitive landscapes

  • finding the pain points in technology and equipment that trigger cost, environmental, and social issues, and identifying solutions and innovations to take performance to the next level

  • optimizing supply chain and procurement through targeted programs to improve controls and reduce costs

 

EXAMPLES OF OUR WORK

Improving Costs and Safety

 

Working with an upstream producer seeking to improve performance in its water operations, we helped identify changes in procurement, pad and network operations, and organization structure to enhance safety and reduce costs by 15 percent.

 

Adopting a Design-to-Value Approach

We supported a North American onshore operator in applying a design-to-value approach to pad design that delivered safety improvements, a reduction in site-preparation time, and savings of $400 million in total cost of ownership across basins.

 

Optimizing the Supply Chain

In serving a large operator with strong performance that still faced cost pressures, we helped introduce best practices in procurement and contracting to deliver savings of $500 million per year in capital expenditure.

 

Identifying Growth Opportunities

For an engineering and construction firm seeking growth opportunities in the North American unconventional oil and gas value chain, we helped to identify three targets and develop strategies designed to boost annual revenues by up to $1 billion.

 

Driving Profitability

To help a national oil company grow tight-oil production and meet its drilling targets, we worked to eliminate unprofitable fields, debottleneck the supply chain, and upgrade contracting, enabling the client to ramp up drilling from five to 100 wells per year.

 

FEATURED CAPABILITIES

We invest heavily in developing proprietary tools, databases, and methods, including:

  • Our North American Supply Model covers 118 basins and incorporates all major sources of supply.

  • Our Offshore Rig Model forecasts the capability of rig activity per basin, based on local production dynamics, and global supply and demand balance.

  • Our Land Rig Model forecasts global land rig counts, along with country-level projections.

  • Our Global Wells Model provides historical data and forecasts for global well counts and well stocks, as well as projections for more than 25 countries.

  • Our North America Midstream Model simulates all regional refineries and transport infrastructure, determines crude flows, and highlights potential bottlenecks.

  • Our North America web tool, OFScope, delivers market spend to 2025 across 26 basins and a full range of service segments for the North American onshore market.

  • Our Permian activity monitoring capability uses satellite imagery to deliver a near-real-time view of drilling, fracking, and production activity of North American shale oil and gas.

Sustaining the base: A new focus in shale’s quest for cash

Production from shale wells declines quickly, but operators can cushion the fall. Sustaining base production is often the best use of capital, a quick way to generate cash, and a key pillar for producers seeking to transform their operations.

 

During the growth-at-all-costs era of US unconventionals, initial rates for new wells went up and up as operators poured their energy, science, and capital into delivering what investors expected. However, they neglected to sustain base production with the same vigor, seemingly resigned to the rapid declines they observed in their wells.

 

In previous articles, we highlighted a shift in industry priorities from growth to generating cash. We argued that continuing to develop for volume is leading to shortsighted decisions and that operators can deliver value to their shareholders only by prioritizing capital efficiency over growth. In this article, we show that sustaining base production often delivers the highest return on capital and offer three starting points for companies seeking to transform their operations.

Future gains in capital efficiency must come from the base

US shale producers have excelled at improving drilling and completion execution: today’s wells deliver 74 percent more volume than three years ago.1 But operators now face a different challenge: actively managing thousands of base production wells. In a typical operator’s well stock, between 70 and 90 percent of wells are more than two years old, and these wells contribute 30 to 60 percent of total production.2 Now that the low-hanging fruit from drilling and completion execution has been captured, operators must turn to sustaining this large base.

That calls for a focus on traditional capital discipline. After all, drilling and completing new wells comprise only one type of capital investment that an oil company can make—and one that should compete for funds with other opportunities in a rigorous capital-governance process. Recent efforts to improve base production have targeted capital-intensive opportunities, such as enhanced oil recovery and refracturing (often as part of a plan to mitigate frac interference). However, the highest returns with the lowest risk usually come from more basic investments in production infrastructure, water management, and efforts to reduce lease operating expenses (LOE).

Typical producers see a net discounted profitability index (DPI)3 of five to 20 in key categories of base production maintenance, as compared with just two to four for new wells. In a rigorous capital-governance system, these base opportunities should take priority over new wells. Exhibit 1 shows how projects for one leading independent were ranked by DPI and capital-expenditure requirements. Production-management projects delivered a much larger economic return than new well drilling in all type-curve areas and required a smaller amount of capital expenditure.

 

Our work with shale producers has shown that transforming profitability should start with low-risk opportunities that pay out quickly. We have identified three areas that apply to all basins and make an excellent starting point: uptime, water management, and proactive lift. Exhibit 2 examines key elements of base production maintenance in these three areas and indicates the likely gains in DPI. Let’s look at each area in turn.

 

1. To keep cash flowing, keep wells flowing

In recent years, independents have devoted most of their efforts to drilling and completing new wells as efficiently as possible, but keeping thousands of wells flowing requires a different focus. To deliver the highest return on capital, operators need to keep facilities and compressors at maximum uptime and restore offline wells quickly.

A systematic focus on mean time to repair like that applied in manufacturing and other heavy industries is the key to restoring offline wells rapidly (Exhibit 3). Top-quartile operators are able to achieve restoration within two weeks, yet we see many operators unintentionally keeping large stocks of offline wells, with backlogs that can last months.

 

A similar approach can be used to reduce planned and unplanned compressor downtime, with an emphasis on strict oversight of third-party vendors used for gas lift compression. Through active performance monitoring, top-quartile operators can keep gas compression uptime above 98.5 percent, even for compressors they don’t own, yet many producers operate at only 96 percent uptime. Though this is a small gap, bridging it would deliver an increase in production that translates directly into an incremental improvement in the operator’s cash flow.

2. Bring water management into the digital age

A high return on investment can also be achieved by improving the efficiency of water management. Depending on the basin concerned, operators’ options include trucking, pipelines, and reuse at new wells. Their choice will be partly determined by factors that include subsurface drivers (such as the amount of water produced) and surface and regulatory constraints on disposal. Although reuse and pipelines can offer the greatest cost savings, the flexibility of truck hauling has made it a popular technique in most basins. Improving the efficiency of water-hauling fleets therefore represents an important means of reducing LOE and improving cash flow.

 

Value over volume: Shale development in the era of cash

Our experience shows that most operators can reduce total water-handling costs by 15 percent by adopting best-in-class practices. To do that, they need to target levers across the value chain:

  • Supply chain. Operators can cut costs and enable predictable operations by consolidating vendors and introducing long-term contracts. They can extract further savings from their water networks through the careful design of haulage contracts, bidding processes, and negotiation strategies.

  • Network optimization. By adopting advanced scheduling tools with oversight from control towers or dispatch centers, operators can continually optimize their system networks.

  • Digital enablement. Tools ranging from GPS-enabled truck tracking to on-site apps and automatic metering and invoicing can drive incremental efficiency gains at every level. When combined with performance dashboards and advanced analytics, they can also be used to determine the best reuse or disposal sites across hundreds of square miles of operations.

 

3. Take a fresh look at artificial-lift management

The third major source of production-management opportunity is artificial lift. Almost every oil well requires artificial lift at some point in its life, but many operators install or activate it only when seeking to restore production in a well that has gone offline. To accelerate cash flow, they should instead install lift at the optimal economic time with respect to the uplift achieved, which comes before the point when lift is needed to restore production. The optimal economic time differs for each lift mechanism, usually occurring one to two years before loss of pressure in oil wells and at the moment of first liquid loading in gas wells (Exhibit 4).

 

Although easy to understand, this concept can be difficult to implement in the field. Producers have several levers at their disposal to enable proactive lift installation:

  • using wellbore models to identify the optimal activation timing for type wells and correlating these timings to ranges of production and pressure to develop guidelines that can easily be applied across large well sets

  • designing dashboards and triggers to flag wells before they reach their optimal activation time

  • planning resources to ensure that rigs, equipment, and personnel are available to execute lift conversions or activations

  • installing lift when a well is drilled for activation when needed, eliminating the need for workover.

A cash-focused approach to lift requires commitment from the organization, since reacting is always easier than active planning, but companies that make the investment will see the benefits.

Digitizing production operations

The common thread across all these production-management opportunities is the importance of digital transformation. The flow of data from wells and water trucks to field offices and production dashboards allows operators to develop an integrated view that drives optimization of the whole system.

Companies that operate in a lean way may well balk at the expense of the data infrastructure and equipment required to sustain digitally enabled operations. However, all independents are heading for a future of low-rate production per well. To achieve incremental gains with this type of asset, they will need to pursue marginal improvements at every operational step—which will require integration and digital enablement at the level of wells, pipelines, facilities, and production-management offices. Operators that invest in this infrastructure will see incremental improvements that add up to a big impact on LOE per barrel.

Implications for investors

Investors need to focus on base maintenance with the same level of scrutiny they apply to new development. In the recent era of growth, they mastered the language of completions and type curves, pinpointing value drivers for independents. In today’s era of cash, they need to give equal attention to production infrastructure and LOE trends. Operators that are able to outperform their type curve after one year of production or kick off a downward trend in LOE per barrel should command a premium.

Value over volume: Shale development in the era of cash

Despite rising production, most US shale producers are showing negative free cash flow. To improve capital efficiency, they need to optimize development strategies for economic value, not volume.

 

The US unconventional sector has been in growth mode for years. Liquids production has risen by 5.1 million barrels per day since 2013, 85 percent of which has come from independents.1 In a previous article, we showed how this growth was a direct response to investor demand,2 with share prices for independents strongly correlated to production growth—but not earnings or cash flow, which has consistently been negative. With the growth phase now at an end, operators need to focus on delivering value by improving their capital efficiency.

Shifting development priorities

During the growth-at-all-costs era, operators poured their energy, science, and capital into delivering what investors expected. That meant maximizing initial rates for new wells, often at the expense of economic metrics, such as net present value (NPV) and free cash flow. This approach drove aggressive decisions on production levers, such as well design, spacing, and choke protocols during early well life. The combined effects of these strategies have left many operators unprepared for the era of cash.

 

In our work with shale producers, we have identified areas in which a growth-oriented mind-set can lead to the wrong outcome for value. Operators should carefully study the relationship between production rate and economic value in these areas:

  • Well design. Instead of basing design decisions on initial rate and defaulting to excessively long laterals and oversize completions, operators should plan around economically optimal completion design, lateral length, and spacing, accounting for parent–child relationships and long-term recovery.

  • Frac interference. Tight spacing, large completions, and hopscotching development plans—often essential in retaining operatorship—have led to widespread frac interference that hinders base production. To maximize value, operators should embed frac-hit avoidance into their development-planning processes and take steps to protect base production by monitoring, tracking, and mitigating frac interference across a range of levers.

  • Drawdown. A bias toward initial rates and a disinclination to study the effects of drawdown may have resulted in reserve losses and suboptimal economics. Operators need to test aggressive and conservative drawdown strategies under controlled conditions and optimize with respect to well economics rather than default to open chokes.

 

All three of these areas pose new challenges on which experts have yet to reach consensus, unlike conventional topics in petroleum engineering that have benefited from decades of research. The best approach for operators is to experiment actively with their wells to optimize for economic value instead of defaulting to maximum rate.

Another driver of value creation is forecast reliability. The desire to meet investors’ growth expectations has led operators to set aspirational production targets and optimistic forecasts that they are reluctant to adjust—and often miss. By contrast, operators with a value mind-set regard accurate forecasting as critical in maintaining investors’ confidence.

Operators need to take steps in each of these areas to improve their capital efficiency and sustain investors’ confidence in their ability to deliver value.

1. Right-size well designs

The first step to increasing capital efficiency is to ensure that the recipe for well design maximizes economic value. The US averages for the main design parameters—namely, lateral length, fluid volume, and proppant loading—have steadily increased year by year, driving a large increase in production per well and pushing up capital outlays (Exhibit 1). The other main inputs, stage spacing and cluster spacing, have also shifted to more capital-intensive designs, although these data are not publicly available in most states.

 

Each design parameter has a positive correlation to both production volume and cost, with an optimal point for economic value. Exhibit 2 summarizes results for leading operators in one subbasin. As the exhibits show, most of the wells have been designed to maximize initial production, with the result that they exceed the optimal economic value for each parameter, depressing capital efficiency. The exception in this example is cluster spacing, in which increasing the investment above the current average yields economic benefits.

 

A better approach is for operators to characterize the optimal economic value for each parameter and then combine the results into a recipe that is repeatable, with continual testing and improvement, across hundreds of inventory locations. To augment the physics-based modeling that engineers use to optimize their designs, we recommend that operators adopt a data-driven approach that uses statistical or machine-learning capabilities and incorporates all analog wells—including those of offset operators—from their basins. With such an approach, engineers can consider larger data sets as they test their designs, quickly update them as other operators experiment nearby, and then overlay the designs on spacing analyses to optimize total section development.

Exhibit 3 shows how applying a machine-learning model to one subbasin revealed a clear economic optimum for fluid and proppant loading, given lateral length, stage spacing, and cluster spacing. For the purpose of optimizing well design for economic value, capital efficiency is defined in terms of barrels produced in 12 months per $1,000 of capital (this metric can be adjusted, but it is important not to use the short periods of initial production—often 30 days—commonly used in the industry). Such an approach can serve as a first step toward full development optimization that accounts for well spacing, well count, and total recovery.

 

Operators should take deliberate steps to counteract the bias toward initial rates that pervades all levels: engineering design, operations, and corporate strategy. To communicate the right priorities to everyone in the organization, dashboards and scorecards should highlight economic metrics above production ones, and explicit targets should be set for value rather than for rate per well.

2. Protect the base

When coupled with tight well spacing, aggressive fracturing treatments have led to an unintended consequence in the form of frac interference (impairment of the base production of existing wells due to the fracturing of new wells). Frac interference covers everything from the degradation of existing fracture networks to the mechanical damage of wellbores when fluid hits producers and is most pronounced during the infill drilling of areas that exhibit partial depletion. This can result in both impairment of the parent wells and poor stimulation of the child wells.

These issues add a layer of complexity to the process of optimizing well spacing and completion design. With more child wells drilled each year than parent wells are, development plans must be designed to prevent and minimize these losses. To understand the advantages and disadvantages of different mitigation techniques, operators should take a structured approach like that shown in Exhibit 4, which shows the decision table for one operator in one subbasin.

 

Our view of frac-interference mitigation is that prevention is better than cure. Losses are best avoided through careful development planning to minimize interactions. Operational levers, such as parent-well preloading or refracturing, should be used when necessary but not as the principal mitigation tools. Although many operators have succeeded with preloading, it always carries a risk that production will not be fully restored. Moreover, not all wells—especially not all new ones—are candidates for refracturing.

As seen in the example in Exhibit 4, the operator prioritized row development for open acreage while planning pad orientation to minimize toe–toe arrangements and tightly spaced parallel infilling. Row development, as depicted in Exhibit 5, mitigates frac interference through sequential pad development, leaving buffer pads around completing wells. This technique offers logistical synergies, if operational complexity can be managed. Operators with discontinuous acreage or drilling plans driven by lease obligations may find that the only levers available to them are operational ones. To prevent interference losses, they should consider advanced techniques in frac monitoring and pinpoint completion as well as preloading and refracturing.

 

In all cases, efforts to mitigate frac interference should be built into planning-cycle processes, with detailed plans for drilling schedules that extend over several years so that operators can compare a range of medium-term scenarios. This may require quantifying the losses caused by interference and estimating the likely impact on future campaigns. Our experience has shown that incorporating frac-hit avoidance into development plans can reduce future losses by more than 20 percent.

 

3. Carefully manage initial rates

The drive to meet production targets can tempt operators into flowing wells too aggressively after completion. Opening chokes can accelerate cash and may be an important temporary step during early flowback, but it is known to cause production impairment in the medium to long term by affecting fluid properties and fracture networks. These physical impacts occur in all basins, albeit with varying degrees of severity (Exhibit 6). Operators will need to conduct controlled experiments to find the best approach, since there is no universal solution across or within basins. Our experience with operators shows that optimizing choke strategies can improve NPV by 10 to 20 percent in oil and dry gas wells and by as much as 100 percent in retrograde condensate wells.

 

When deciding on choke protocols, operators should be guided by the economic value of each well as a function of its drawdown. Since the effect of aggressive production on downhole impairment is not well understood, operators should experiment with choke settings while monitoring pressure and rate. Established techniques, such as rate-transient analysis, will shed light on the subsurface dependencies of drawdown, especially in the identification of stimulated reservoir volume (SRV) and skin impact. However, accelerated production may justify a loss in long-term reserves from SRV degradation. In making such decisions, NPV per well should be the sole criterion.

4. Produce reliable forecasts

Independents’ growth-focused business models are being undermined by a widespread inability to forecast production accurately or achieve targets. On average, operators fell short of production guidance by 4 percent in 2018, with considerable variation among companies.3 This failure to achieve production targets comes not only because wells are underperforming but also because overoptimistic forecasting is prevalent across the sector.

Once an operator has optimized its development plans for value, it should gear its forecasts to trustworthiness so it can promote investor confidence. Following a few guiding principles will help to ensure forecasting discipline and reliability:

  • Honor actuals above all else. Ensure that type curves and base declines used for investor guidance are kept up to date and are based on realized rates, irrespective of earlier forecasts. It is acceptable to use aspirational targets internally to drive improvement, but forecasts issued externally must reflect the most-likely outcomes.

  • Match long-term, basin-wide trends. Assumptions about base decline should be checked against basin-wide actuals. For example, in mature plays with thousands of wells and lengthy producing histories, operators can directly fit Arps’s b-factor governing long-term decline4 for historical wells, meaning they no longer need to resort to commonly used but unvalidated rules of thumb.

  • Account for infill effects. Forecasts should include realistic estimates for child wells and account for both depletion and frac-interference effects, which can be expected in most cases. The simplest approach is to apply a type-curve adjustment factor to child wells. A more advanced forecast can account for deferred shut-in volumes and losses from frac interference.

 

Implications for investors

It is time for companies operating in the core areas of mature basins to be valued according to a new set of priorities. After ten years of testing and acreage consolidation, they should be expected to deliver positive cash flows across cycles. Such a cash-flow reset may entail short-term reductions in production volumes, followed by improvement in margins. Given sector-wide shortfalls in targets, investors should rigorously challenge production forecasts and be prepared for downward adjustments. Operators that can reliably generate cash while meeting realistic targets should command a premium.

 

The era of cash is forcing operators in all basins to rethink their development strategies, which depend on engineering concepts that are new to the industry and have yet to achieve consensus among experts. As the scientific understanding of completion optimization, frac interference, and drawdown optimization improves, operators must take a careful approach to development and continually test their plans to ensure that they are maximizing economic value.

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Issued by The Jeeranont Company Limited is authorised and regulated in the USA by the Financial Conduct Authority. UNITED STATES OF AMERICA