Presentation Date: Tuesday, October 18, 2016
Start Time: 1:50:00 PM
Presentation Type: ORAL
As cost efficiency becomes the priority across the industry, some operators have turned to advanced microseismic analysis techniques to improve profitability and strategy planning for unconventional field development. Through a process that quantifies a treated reservoir’s current and future productivity, the short- and long-term production for entire fields can be estimated early on in a field’s development cycle.
These early production predictions are available immediately after well treatment, eliminating the typical 6-to 12-month wait time for production results. The time saved enables operators to immediately evaluate the effectiveness of treatment strategies and, therefore, optimize planning for the remainder of the field without waiting for actual production data from each well.
People often worry about the uncertainty in microseismic data, but our ability to create a model that is consistent with actual production suggests that uncertainty is sufficiently constrained through the outlined process. This is proven by case history given here.
Presentation Date: Thursday, October 20, 2016
Start Time: 11:25:00 AM
Presentation Type: ORAL
Here, a method of passive seismic imaging using multicomponent (3-C) data is presented. It is a Beamforming/Kirchhoff type migration, which is based upon the isotropic elastic wave equation within geometrical optics theory. To account for the effects of the source mechanism, polarity corrections are applied.
Mathematically, the goal in a passive seismic survey is to characterize the source term in the elastic wave equation, given seismic velocities and measured displacements at some number of observation points. Following Haldorsen et al. (2013) approach, using Helmholtz decomposition (Muller, 2007), the source wavefield can be decomposed into a curl-free longitudinal component (L) and divergence-free transverse (T) components. They are utilized to locate and characterize the seismic event that sourced the wavefield. The method can be implemented for both surface and downhole receiver array geometries. Here we are presenting the method as it applies to downhole surveys. Both synthetic and field data examples are demonstrated.
The synthetic example proves the feasibility of the imaging technique, by producing the resulting image coincident with the modeled synthetic event. The accuracy of the approach with a real world example is validated by quality-control of the imaging procedure, by the relative position to a treatment well of the event locations, and by the match of the imaged perforation shot to its known location.
Passive seismic data recorded by surface arrays, which have large apertures, wide azimuths and high fold, are routinely used for imaging of microseismicity that occurs during hydraulic fracturing (Duncan and Eisner, 2010). Mapping of the microseismicity created during hydraulic fracturing, when tight shale formations are stimulated in order to increase permeability, is critical to understanding the well efficiency, to optimize completion processes and to maximize production. The method presented here can be used for 3-C data recorded both on/near Earth’s surface and/or in downhole deployments to characterize and locate passive microseismic events. We present the theoretical basis, from which the 3-C imaging solution is derived. We then demonstrate the method using both synthetic and real field data.
Summary The performance of a combined surface and downhole microseismic monitoring array is analyzed in terms of detection sensitivity, resolution and velocity sensitivity. While the relative merits and limitations of downhole and surface microseismic monitoring suggest that the two techniques are complimentary, this analysis suggests that the performance of a combined array offers modest improvements over a surface array alone. Introduction Currently there are two acquisition methods in use in the industry for microseismic monitoring of hydraulic fracturing: downhole arrays and surface arrays (Maxwell, 2010; Duncan and Eisner, 2010). Downhole monitoring places the sensors closer to the fracture events in a relatively quiet environment compared to surface arrays. Shorter travel paths in this geometry result in stronger signal, which allows smaller magnitude events to be detected as well as increased signal bandwidth.
Cramer, Ron (Shell Global Solutions) | Krebbers, Johan (Shell International B V) | van Oort, Eric (Shell Exploration & Production) | Lanson, Anthony Paul (Shell E&P Technology Co.) | Palermo, Robert (Shell Oil Co.) | Murthy, Ajith (Shell Global Solutions) | Duncan, Peter (MicroSeismic Inc.) | Sowell, Tim (Invensys)
The Digital Oil Field (DOF) real time data structure as applied to drilling, reservoirs, wells surface production facilities, pipelines and downstream systems has evolved as bit of a muddle with little overall design and structure and little thought given to the underlying data foundational requirements.
Microseismic monitoring has been largely accepted as an important adjunct to the hydraulic fracturing of unconventional gas reservoirs. Both surface and downhole methodologies are now common for the performance of such monitoring, each with its advantages and challenges. This paper discusses the state of the technology today and where current work is being directed at reducing cost and enhancing the value of microseismic monitoring.
While the fundamental concepts of microseismic monitoring of hydraulic fracture well stimulation were captured by J. R. Bailey (1973) in his patent, it has really been within the last 10 years that the technology has become commercially and technically important, especially in the unconventional gas and oil plays where hydraulic fracturing is an essential element of every completion. Today, perhaps as many as 10% of the unconventional completions are monitored and technical arguments can be made for driving that percentage higher, if it can be done at reasonable cost.
There are two alternative microseismic monitoring techniques commonly used today: surface and downhole monitoring. As well, there are three general classes of techniques for locating microseismic (MS) events: hodogram techniques based upon the particle motion of direct arrivals, triangulation schemes based upon arrival times of direct waves, semblance methods based upon stacking of waves without arrival time picking. All three classes of location techniques can be employed in conjunction with either surface or downhole sensors. Since the first two classes are based on discrete arrival time and signal polarization picks, downhole sensor deployment is often necessary in order to resolve the location. On the other hand, the aperture and fold requirements of the semblance class of location techniques tend to favor a large areal spread of sensors as can be most conveniently achieved with a surface or near surface array.
In this paper we will briefly report on the current state of the microseismic monitoring practice as applied to unconventional gas exploitation, as well as listing some of the areas of current research and development that are directed at making the technology more valuable.
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