Brian Toelle, Ph.D.
I retired as a "Professor of Practice" in the Department of Energy and Petroleum Engineering" at the University of Wyoming. I enjoyed teaching in the College of Engineering and Physical Sciences and conducting my research in areas I found interesting. My personal webpage is at http://toelle.us
Address: betoelle@comcast.net
Address: betoelle@comcast.net
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These tools allow an interpreter to visualize of the complete dataset all at once, importing not just the seismic data and its various attributes but also wellbores, logs, and horizon and fault interpretation. Opacity tools allow specific ranges of these attributes to be viewed while other ranges are left transparent to allow the other attributes in the blended volume to be seen. This technique is now being used to locate subtle geologic features that would have gone unnoticed using previous visualization tools.
Although initially developed for use with 3D seismic volumes, blended attributes can now be developed for 2D seismic data also. This greatly expands the area where these techniques can be applied. The vast majority of the seismic data acquired in the Appalachian Basin has been, and continues to be, 2D. Blended seismic attributes of 2D seismic data could become a valuable tool to the Appalachian explorationist.
The US Department of Energy has funded a study of an on-going enhanced oil recovery project being conducted on a reef within this trend using the injection of CO2. The Charlton 30/31 reef, located in Otsego County, like many other reefs in the play, was discovered and developed during the 1970s and 1980s. This field has completed its primary production phase, during which 6 wells produced 2.6 million of the field’s estimated 7 million barrels of oil in place. This reservoir is characterized as a low porosity, low permeability limestone matrix with irregular dolomitized intervals providing a secondary network of higher porosity and permeability, which controls fluid flow throughout the reservoir. The estimated average porosity in this reef is just slightly over 6%. As part of this study the reservoir attributes identified at the Charlton 30/31 reef were extended to the entire Northern Reef Trend in order to determine its CO2 sequestration capacity. Additionally, the potential oil recovery has been estimated.
The use of opacity tools that allow specific ranges of seismic attributes to be viewed while other ranges are left transparent are becoming common place. These software tools allow additional features within a blended attribute volume to be rapidly identified. This technique is now being used to locate and interpret subtle geologic features that would have gone unnoticed using previous visualization tools.
These new tools also allow the visualization of the complete datasets, importing into one 3-dimensional canvas seismic data as well as horizon and fault interpretation, wellbores, and well log data. This provides an excellent medium for the integration of multiple data types, and allowing not only the geophysicist but also the geologist, petrophysicist and reservoir engineer to view their data as it relates to the datasets from the other disciplines. These software packages are rapidly becoming the standard tool for project teams to integrate and present their findings.
Although many of these techniques were initially developed for 3D seismic data, blended attributes can now also be created for 2D seismic datasets. This greatly expands the locations where this method may be applied. The vast majority of the seismic data acquired in the Appalachian Basin has been, and continues to be, 2D. The use of various seismic attributes, as well as blended attributes using 2D seismic data is rapidly becoming a valuable tool in the Appalachian Basin. During this presentation a number of examples of blended seismic attribute volumes and 2D lines will be shown as well as examples of volume visualization techniques.
But what is the next step? Where does the industry go from here to obtain the next computing “big leap” that will give them a competitive edge? Many believe that it will be by doing the same thing, only faster, more efficiently, and through utilization of greater amounts of Data Management. This will be an important next step.
However, common computing systems have become so powerful that we can now go beyond that into Knowledge Management (KM). Knowledge is the primary asset of a company and without it no other assets can be efficiently managed. Simply recognizing that it exists is not enough since its proper use can have a fundamental impact on the daily business of a company. Today, a number of tools exist that may be used for Knowledge Management. Nevertheless companies only use these tools for separate, isolate activities and may not even recognize them as being KM oriented.
A few far-thinking companies have recognized the potential value of KM and are moving toward formal Knowledge Management Systems. But, as with most new frontiers there are many questions that must be answered first. What is a KM system, what will the benefits be to workers in the oil and gas exploration industry and how do you build one?
To answer these questions one must understand what knowledge is and how it differs from data and information. In the petroleum exploration industry knowledge, is basically present in two forms: what was learned about an area of interest, and how was it learned. By having rapid access to a properly managed Knowledge Repository, E & P workers can quickly access the knowledge pertaining to a field or play area discovered by previous workers and the work procedures used to discover it.
In order to build a KM system that enables E & P workers to routinely capture the knowledge that they develop on a day-to-day basis, companies must take three critical actions:
1) Develop a “Knowledge Oriented” work environment where knowledge is considered a valuable company asset:
2) Align the company's work flows for effective use of its best knowledge; and
3) Invest in technological tools that make the capture, storage, exchange, and application of knowledge effective and efficient.
This presentation will investigate these systems and why they are becoming more and more prevalent throughout our industry. The use of KM oriented tools, such as net-based collaboration tools, by smaller companies and contractors will also be discussed.
Three Miocene sand fields, NW Dauphin Island, NE Petis Bois, and North Dauphin Island fields, will make up this new facility. These are located between the main land and Dauphin Island, just off the Alabama coast line.
Existing field facilities, (see Figure #3) constructed during these field's primary production phases, are to be modified for gas storage. In addition to these modifications a number of new, horizontal wells will be drilled within the reservoir. In order to plan the placement of these new boreholes a full reservoir study was performed, including the
analysis of a 2D seismic grid.
Recent exploration activity in the eastern portion of Okfuskee County, Oklahoma has included the acquisition of a 36 square mile 3D p-wave seismic survey. Through the use of blended seismic attribute analysis this data set has revealed fault systems that are believed related to the Alabama-Oklahoma transform and the Iapetan Rift systems. These features will be discussed during this presentation.
The US Department of Energy has funded a study of an on-going enhanced oil recovery project being conducted on a reef within this trend using the injection of CO2. The Charlton 30/31 reef, located in Otsego County, like many other reefs in the play, was discovered and developed during the 1970s and 1980s. This field has completed its primary production phase, during which 6 wells produced 2.6 million of the field’s estimated 7 million barrels of oil in place. This reservoir is characterized as a low porosity, low permeability limestone matrix with irregular dolomitized intervals providing a secondary network of higher porosity and permeability, which controls fluid flow throughout the reservoir. The estimated average porosity in this reef is just slightly over 6%. As part of this study the reservoir attributes identified at the Charlton 30/31 reef were extended to the entire Northern Reef Trend in order to determine its CO2 sequestration capacity. Additionally, the potential oil recovery has been estimated.
project, a four-dimensional (4-D) P-wave seismic survey was acquired in an attempt to monitor the fl ow of CO2 through the reservoir.
A three-dimensional (3-D) P-wave seismic survey was acquired prior to the injection of the CO2, which served as the baseline for the 4-D survey. Various interpretation methods were performed on this initial 3-D data set in order to develop a reservoir characterization and a dynamic model for multiple reservoir simulations. During the initial phase of the project, a relationship was identified between the low instantaneous frequency derived from the full-azimuth seismic volume and zones of high
porosity and permeability in the reef identified from well logs. This relationship was used for the reservoir characterization. Forward models developed to approximate the reservoir’s characteristics support the relationship. Multiple analyses and data sets acquired following the creation of this reservoir characterization confirmed the interpreted matrix porosity distribution developed using this relationship.
Following the injection of 29,000 tons of CO2 into the Charlton 30/31 reef, a second 3-D P-wave seismic survey was acquired that served as the monitor survey for the 4-D survey. Amplitude analysis of the monitor survey provided a good correlation to zones predicted to be filled with CO2 by the final, predictive reservoir simulation. However, one particularly strong amplitude anomaly immediately to the northeast of
the CO2 injection point was observed that suggested this reef may contain fracture porosity as well as zones of high matrix porosity.
Although few individual, open fractures have been reported in these reefs, the available data sets are not optimum for the recognition of vertical fracture systems. In an attempt to identify and characterize any open fracture trends that may exist within this reef, four azimuthal seismic volumes were developed and analyzed. Isofrequency
volumes were developed from these azimuthal volumes through spectral decomposition, and then they were compared in an attempt to identify frequency attenuation within the reservoir. In theory, zones of high matrix porosity and permeability affect all azimuthal volumes in an isotropic manner, producing zones of frequency attenuation in all azimuthal volumes to approximately the same degree. However, due to their
often linear nature, fracture trends produce anisotropy that is potentially recognizable in an azimuthal volume.
Increased amplitude in some lower frequencies, specifically 15 Hz, in the 160° azimuthal volume was observed to the northeast and southwest of the CO2 injection point on the same time slice corresponding with the CO2 flow interpreted on the 4-D monitor survey. This suggests that some open, northeast-trending fractures exist near the injection point, resulting in increased directional system permeability at that location that channels more CO2 to the northeast than is explained by the matrix porosity and permeability alone.
The results indicate a high degree of thermal maturity within the Permian petroleum system with high transformation ratio values. For the Cretaceous petroleum system, the results also indicate a high degree of thermal maturity and transformation ratios in the Lower Cretaceous with decreasing thermal maturity for the Upper Cretaceous formations. The cumulative erosion model indicates the majority of the erosion took place on the margins of the basin. The modeling indicates the Upper Cretaceous Frontier Formation and overlying Cody Shale are within the oil generation window over a large portion of the eastern side of the basin and are within economic drill depths.