Integration: The New Business As Usual

石油工人2015

Integration: The New Business As UsualAaron Gatt Floridia, Schlumberger Reservoir Characterization Group
Thursday, October 1, 2015 - 9:00am Print

• Share thiswith others[size=1em] [size=1em] [size=1em] [size=1em]
• Email this page
  

With plummeting crude oil prices and highly unstable market conditions, upstream industry projects worldwide will likely face continuing challenges for the foreseeable future. Achieving a strong return on investment in any play remains problematic unless operators significantly reduce both the cost and risk of oil and gas development projects.

Project economics are sensitive to a multitude of factors, including recoverable reserve volumes; the mix of fluids present; reservoir quality and heterogeneity; drilling efficiency; completion design; and the wellhead equipment, production and processing facilities involved.

For example, the infrastructure required to develop and produce natural gas is highly sensitive to the precise composition of the effluent. Failing to detect the presence of hydrogen sulfide (H2S) gas or underestimating its concentration can put human health and safety at risk and cost tens of millions of dollars in damage resulting from corrosion and equipment failure. Overestimating the H2S concentration also can be expensive thanks to over-engineered treatment systems.

Accurate measurements
Cost and risk cannot be effectively managed by relying on generalizations or uninformed estimates—accurate measurements are the necessary basis for achieving economic success. There is a growing appreciation of this relationship in unconventional plays, where the failure to unravel vertical and lateral variations in mechanical rock properties and reservoir character from well to well or even along a single long lateral can undermine a drilling campaign or stimulation operation.

Historically, it has been a challenge to obtain sufficient geoscience and engineering data to properly understand shale reservoirs, which have turned out to be more complex than anyone imagined. Going forward, it will be essential to not only acquire more data but to integrate diverse measurements across the reservoir life cycle to minimize risks, uncertainties and associated costs. No single measurement, no matter how sophisticated, can ever be definitive.

Typically, isolated measurements are taken by multiple contractors or various segments of an oilfield services company at different depths and different points in time—some prior to drilling, some in real time while drilling, others by wireline and still others during flow-testing or laboratory analysis. Each disconnection between the measurements, tools and service providers is yet another opportunity for vital information to fall through the cracks.

To help oil and gas companies meet this challenge, oilfield services providers must begin integrating previously segmented drilling, formation evaluation, reservoir characterization, testing, and completion and production data and services. Collaboration across these silos and the integration of measurements at every scale, from core to seismic survey, across the E&P life cycle must become routine—in effect, the new “business as usual.”

A U.S. operator engaged Schlumberger to design an integrated hydraulic fracture treatment strategy for a vertical pilot well and new horizontal laterals in the Wolfbone Formation—an interval of stacked, heterogeneous conventional and unconventional reservoirs in the Permian Basin.

Technical experts integrated measurements from four advanced wireline tools. All reservoir data were fed into the Mangrove engineered stimulation design in the Petrel E&P software platform to optimize treatment stages, perforation placement and job execution by using the HiWAY flow-channel fracturing technique.

Despite a 30% reduction in proppant and 6% less fluid per stage than conventional stimulation, initial oil production ranked among the Wolfbone play’s top 20%. The operator identified cost savings of $734,900 per well. On the basis of the new integrated measurements and models, the company drilled and completed its first horizontal well in a new, deeper target interval. Initial production was 60% higher than that of offset laterals, and the 10-month cumulative production was 39% higher. Post-project analysis of the integrated drilling, completion and production data enabled the operator to further improve plans for subsequent operations.