The Adaptive Well Factory: An interview in the December 2010 World Oil magazine
Posted by D Nathan Meehan December 17, 2010
I joined the World Oil Advisory Board in 1996 while working for a large independent oil company. Each December World Oil (and my subsequent employers) have allowed me wide latitude to opine on technical, commercial and related issues that I think will be important to the industry. For this blog entry I have included this article and I recommend that you also take a look at the other World Oil articles as well.

The adaptive well factory

The transition in the drilling industry from segmented operations to fully integrated operations can potentially allow operators to drill hundreds or even thousands of roughly similar wells at costs that will decline over time. Factory costs related to scale often see performance improvements that allow 10–20% unit cost reductions as volumes double. Conversely, the highly variable costs associated with manufacturing many different items often see unit cost increases of over 20% with each doubling of variety.

Operators in unconventional gas and oil reservoirs are keen on lowering costs by rapidly identifying drilling and completion approaches that are nearly optimal, given the massive capital costs associated with developing these reservoirs. This has been true of essentially every large drilling campaign.

The difference today is that the tools used to understand unconventional reservoirs have changed; the wells are primarily horizontal with many multistage hydraulic fracture treatments, and new petrophysical and geomechanical approaches are required. Recent technological advances will be essential to leverage the scale of unconventional drilling activity while addressing the wide variety of reservoirs encountered.

Advanced directional drilling and LWD technologies are now commonplace. The quality of data gathered during drilling allows operators to geosteer in thin zones with complex structures and evaluate the formations in near-real time. Completion practices have changed dramatically over the last decade as a result of the focus on very long horizontal and multilateral wells in unconventional reservoirs. Dozens of separate frac treatments in wells with either plug-and-perf or openhole-packer and sleeve methods are routinely capable of generating significant hydrocarbon rates from rocks that until recently were not considered reservoirs.

One new trick the industry has learned in the last decade has been to integrate geomechanics into our understanding of the reservoir. Along with geology, geophysics, petrophysics, reservoir and production engineering, geomechanics has become an essential tool in understanding where and how to drill, complete and operate wells more effectively.

My first encounter with geomechanics was as a graduate student studying hydraulic fracture orientation and analyzing wellbore breakouts. While I was only interested in the fracture azimuth, I learned just how valuable image logs could be for understanding wellbore issues—particularly wellbore stability in directional wells—and, later, for understanding critically stressed fractures.

One of the many contributions of geomechanics is particularly relevant for understanding the performance of unconventional gas and oil reservoirs. Critically stressed fractures can be major contributors to production in shale reservoirs. Flaws that are nearly impermeable otherwise but are oriented in certain directions with respect to the stress fields may slip by tiny amounts in shear and result in substantial local increases in flow capacity. Conventional hydraulic fracturing models are dominated by tensile failure. These fractures alone do not explain the performance of successful shale wells nor the substantial microseismicity observed while stimulating such wells.

Geomechanical models help explain and predict the orientations, frequency and abundance of critically stressed fractures and enable operators to optimize stimulation designs and well spacing. Mineralogical analyses of shale reservoirs using pulsed neutron and other geochemical tools allow us to understand details of the depositional environment, identify shale lithofacies, make realistic estimates of effective porosity, identify and compute total organic carbon, and improve the placement of laterals and stimulation designs. Ultimately, reservoir models must be able to more accurately predict drainage areas in order to optimize interwell spacing so the resource can be drained without overdrilling.

Hydraulic fracturing has changed radically from a few decades past where the standard jobs involved high concentrations of crosslinked gels with proppant concentrations of 8 ppg or greater. Many applications have seen success using “water fracs” that consist of vastly greater quantities of lower-concentration uncrosslinked gels with low sand concentrations (on the order of 0.5–1 ppg) pumped at dramatically higher rates. Geomechanical models are highly predictive of where such treatments will be most successful.

However, water fracs lead to accelerated wear and tear on pressure pumping equipment. High levels of activity and increased repair and maintenance costs have resulted in higher prices for pressure pumping services. Innovative ways to drill and complete large numbers of wells and frac stages to optimally drain shale reservoirs hold the promise of significantly lowering the total cost per barrel of oil equivalent in large-scale drilling campaigns.

Many operators have puzzled over the high variability from location to location in unconventional reservoirs. In many cases, these variations cannot be easily predicted from conventional logs or even cores. Because many large areas show similar distributions of well performance based on estimated ultimate recovery and little spatial correlation, operators may use statistical methods to estimate the results from further development drilling and get good agreement in the aggregate. For a given well that has the appropriate measurements, we can routinely simulate and match well performances using reservoir simulators and specialized type curves designed for the types of fractures we think are created. Such models rely on accurate porosity estimates and reservoir descriptions.

When the industry doesn’t make such measurements, it is impossible to fully understand the spatial variability of key reservoir variables, how to predict their impact on well performance, how to predict their spatial distribution or calculate them from measurements. In these cases, we cannot predict or explain the variability of well performance for similarly completed wells. This will lead to a sub-optimal approach to the drilling and completion of hundreds and potentially thousands of wells.

Shale reservoirs are certainly going to be productive of oil and gas in many places around the world. The optimal drilling factory will need to make the appropriate measures, incorporate new technology and different reservoir-based views of unconventional reservoirs and integrate them into development plans “on the fly” to create the greatest value. If product prices were significantly higher, sub-optimal development would be more forgiving. The exciting challenges posed by unconventional reservoirs are some of the most important things we must “get right.”

Hydraulic fracturing of horizontal wells with dozens of individual frac jobs is now routinely possible, leading to the potential for larger drainage volumes from individual wells and better optimized placement. Advanced geomechanical modeling has greatly improved our understanding of shale behavior. In the early days of horizontal wells, there were similar questions about well placement, optimal lengths and incremental recoveries. As the industry’s experience grows, operators who invest in understanding these reservoirs will inevitably outperform the rest.

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