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As cost efficiency becomes the priority across the industry, some operators have turned to advanced microseismic The process for using microseismic data to predict analysis techniques to improve profitability and strategy multiple-well production volumes begins with determining planning for unconventional field development. Through a the fracture intensity as described by a deterministic process that quantifies a treated reservoir's current and discrete fracture network model. The fracture intensity is future productivity, the short-and long-term production for then translated into reservoir permeability using an entire fields can be estimated early on in a field's analytical method based on Oda's theory.
Presentation Date: Tuesday, October 18, 2016
Start Time: 1:50:00 PM
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.
While the relative merits and limitations of downhole and The combined array imaging will be evaluated with models surface microseismic monitoring suggest that the two that assume the compressional wave beamforming will be techniques are complimentary, this analysis suggests that used to image the microseismic events. Compressional only the performance of a combined array offers modest imaging was chosen as, in our experience, shear energy is improvements over a surface array alone.
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. This has lead to disintegrated systems and inefficiency in attempts to integrate the multi-various systems and components. Current real time data standards are based on a combination of downstream and upstream proprietary vendor standards that are growing more and more higgledy-piggeldy as more systems are deployed. Aggravating the problem is the ever growing volumes of data which needs to be transformed into useful information to facilitate better and more timely decision-making. Hence the purpose of this paper is fourfold to: - Define the problem in terms of the current overabundance of data systems and standards; - Document current and foreseeable data business requirements; - Define the required integrated data foundation capable of handling the ever growing data volumes and providing appropriate, timely and accurate information to those that need to know; - Identify the business value that can be attained with this more structured and standardized approach. The ultimate aim is to provide a solid foundation upon which the Digital Oil/Gas field can grow and flourish and a corresponding business justification.
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.
Summary The accurate imaging of steep flanks of salt domes has long been a challenging problem for exploration geophysicists. The problem continues to be relevant today as more and more salt domes are being shot with 3D seismic in order to exploit remaining hydrocarbon reserves. Unfortunately, the seismic images of steep salt flanks are often not satisfactory; they are either broken or appear as smeared events. Interpretation of the salt body in these cases is difficult and somewhat confusing (see figure la). In this paper we present a method to solve the difficulties in accurately imaging and positioning steep salt flanks.