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Monitoring microseismic fracture development to optimize stimulation and production in aging fields

Schlumberger, College Station, Texas, USA

Les Nutt and Valerie Jochen

Schlumberger, Houston, USA

William Underhill and Julian Drew

Schlumberger, Kanagawa, Japan

Corresponding author: jcalvez2@college-station.oilfield.slb.com

The first 20% of the full text of this article appears below.

The increasing worldwide demand for energy motivates the oil and gas industry to develop reservoirs that are continually more difficult to produce. These difficulties are due to the reservoir characters (tight gas sands, coal bed methane reservoirs, condensate reservoirs, deep and ultradeep reservoirs, etc.) or their history (mature fields, etc.) One way to improve and accelerate hydrocarbon recovery is an effective stimulation program.

The integration of fracture simulation and well performance can provide valuable insight into the effectiveness of a stimulation treatment. This process requires the integration of several analytical tools. The actual rate and pressure response from the stimulation are matched with a fracture simulator to determine the "observed" fracture half-length. Next, the "effective" fracture half-length is determined from the production response of the well. The resulting "effective" half-length is then compared to both the prejob estimates and the "observed" results.

Several analytical techniques are currently at the engineer's disposal for postproduction analysis (pressure transient testing, transient production analysis, production simulators, etc.) These methods have proven valuable in determining the parameters critical to understanding the reservoir behavior and their impact on the hydraulic fracture stimulation. However, to be valid, a production analysis requires an extended poststimulation production record. Although these methods provide reliable estimates of specific in-situ reservoir and hydraulic fracture transmissibility properties, they do not fully describe the geometry of the hydraulically-induced fracture system.

Several proven technologies can aid in defining the fracture system geometry (temperature log, radioactive tracing, tiltmeter survey, etc.). Unfortunately, each tool has shortcomings. For example, a temperature log provides information for a volume within a few feet of the wellbore and only gives some insight as to the height of the induced fracture. Similarly, a radioactive tracer log only provides nearwellbore fracture height information. Surface and downhole tiltmeter mapping is a more recent technology . . . [Full Text of this Article]