Given the price of oil, many operators in unconventional resource plays find themselves at or near the economic breakeven point. In such uncertain times, it’s critical to reduce the operational cost per boe. This can be achieved by either lowering the numerator (cost) or by boosting the denominator (production) or, better yet, by doing both.

Traditional factory approaches to drilling and hydraulic fracturing have focused primarily on the cost side of the equation, whittling expenses by applying essentially the same formula to every lateral as rapidly as possible. Until the oil price crash, this might have appeared sufficient. Today it’s a formula for failure. The industry now knows that unconventional reservoirs exhibit extreme variations, both laterally and vertically. Every shale is complex and unique.

To ensure smarter, faster decisions about where and how to drill and where and how to fracture, operators must integrate all available data, information and knowledge in a single, continuously updated subsurface model. Unfortunately, tools designed for conventional reservoirs need significant modification to accurately capture, model and simulate the heterogeneities and natural fractures present in shales. New technology is essential.

Commercializing proven and new technologies
Two years ago Halliburton began deploying a wide range of geoscience and engineering tools on a common software and data platform to deliver the new CYPHER Seismic-to-Stimulation Service for unconventional reservoirs. The platform provides advanced functionality for integrated geophysical, geological, petrophysical, geomechanical and engineering interpretations. With these tools, joint client and service company teams have built more comprehensive models, applied multivariate statistical analyses to identify sweet spots, modeled complicated fracture networks and accurately simulated induced fractures. The tools also enable teams to run flow simulations, perform history matching and efficiently evaluate completion designs.

The company is commercializing its DecisionSpace Unconventionals software. Recent enhancements seek to offer asset teams a complete end-to-end geoscience, reservoir and engineering solution for the full E&P life cycle. DecisionSpace Unconventionals provides a common multidiscipline subsurface model, updated continuously with new data before, during and after each well is drilled to help with improved decision-making and increased team collaboration.

Key technologies include patent-pending unstructured gridding, which automatically creates higher resolution grid cells surrounding natural and induced fractures, with coarser cells elsewhere. This can improve the usability of flow models, history matching and performance predictions. A new fracture productivity tool will provide a simplified interface to the reservoir simulator, enabling users to enter data easily, build sophisticated models and quickly see the impact of various drilling and completion scenarios over the life of the reservoir.

Improving both sides of the equation
Used in several major North American shale plays to date, these integrated workflow tools have helped to both decrease the numerator and increase the denominator of the cost per boe ratio.

For example, in a step-out development just outside the core productive area of the Barnett Shale, an operator had completed only three successful wells out of 11. Production was poor and highly inconsistent from well to well (according to URTeC paper 1920572). To avoid abandoning the asset, the company shot 3-D seismic, brought in the new seismic-to-stimulation reservoir technologies, acquired additional formation data and developed a comprehensive earth model, which revealed tremendous vertical heterogeneity. The multidiscipline asset team identified a more promising target interval, determined how to land and geosteer laterals more accurately, created a complex fracture model from borehole image and microseismic data,
ran flow simulations, and revised and optimized its previous completion strategy.

As a result, IP improved by more than 50%, well-towell performance became far more consistent, and average post-project well costs shrank initially by nearly 5% and subsequently by an additional 22% despite new data acquisition and higher proppant volumes.

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