Target Sweet Spots & Forecast Production in Shale Reservoirs
Production variability in unconventional reservoirs at the basin-to-frac stage level is driven by geologic and geomechanical heterogeneity, as well as the effectiveness of stimulation of natural fracture networks. The synthesis of technologies to model the reservoir heterogeneity and frac effectiveness while applying appropriately acquired and processed high-confidence microseismic data to monitor the reservoir response to the treatment and to validate the geologic and geomechanical models, is becoming a major contributor to the economic optimization of unconventional reservoir developmen, including where to lease, pad locations, where to land laterals and where to frac.
Variable well performance in unconventional reservoirs is fueling the need for better reservoir understanding. Statistical pattern drilling is no longer a viable solution, and operators are searching for ways to make every well hit the sweet spot.
With a significant distribution of wells being poor or average producers how can we better target the good producers? Almost 550,000 fracs were performed last year in the U.S., but research shows that 25% – probably more – failed to meet performance objectives.
Innovation focused on unprecedented integrated, technology-led approach to understanding and managing complex reservoirs is the only solution for an $11 billion problem. Geologic variations at the field- and well-scale are captured by our seismic-enabled, geologically driven Shale Capacity model, defined as the product of four key shale drivers:
- Fracture Density
When drilling a shale reservoir, the percent of the lateral well length in a high Shale Capacity reservoir has a strong correlation (.7-.9) with the resulting relative well performance. Performance variability at the frac stage level can now be modeled using a new fracture geomechanical simulation of the interaction of hydraulic fracturing with naturally fractured reservoirs in order to optimize well spacing and frac treatments. This geomechanical simulation of the propagation and interaction of multiple hydraulic fractures with natural fractures provides the industry with the ability to predict:
- Reservoir strain (proxy for microseismicity)
- Differential stress
- Local maximum horizontal stress direction variations
- Contribution to production of each stage before drilling and stimulation of a given well or pad
Variability permeability models in the SRV are developed accounting for geologic heterogeneity and fracturing effectiveness using reservoir simulation. This means optimized well spacing and more accurate EUR forecasts.
Although each play is unique, certain things will hold true for the "ideal shale well":
- The well must be drilled in a zone that has high TOC
- Intercepted shale must be brittle enough to frac
- Induced fractures resulting from the frac job must intercept a natural fracture system and porosity
- Induced fractures must remain open for a sufficient period of time to allow economic volumes of hydrocarbons to be produced
But engineers and geoscientists are busy keeping up with the drilling schedule. Drilling and fracing is all consuming, so taking advantage of the wealth of information contained in the seismic data often takes a backseat.
What if you could turn well and seismic data into actionable knowledge and easily determine the optimal surface location to place a pad, the best azimuths for their laterals, the precise landing depths, and which stages will best contribute to production? What if you could help your drilling engineers guide the drill bit toward the sweet spots and away from faults and other drilling hazards, and help the completion engineer optimize the performance of each frac stage to maximize drainage areas and frac efficiency?
With integrated GeoEngineering™ workflows, you can.
Target the Sweet Spots by Knowing Where2Drill & Where2Frac
Please consult the SPE website for information regarding download of SPE technical papers.