SEISMIC IMAGING OF STRUCTURAL, STRATIGRAPHIC AND DIAGENETIC PLAYS

Based on a workshop sponsored by PTTC's Appalachian Regional organization held on March 6, 2003 at West Virginia University, Morgantown, West Virginia

BOTTOM LINE

The focus of the workshop was on the use of seismic data for exploration and development of hydrocarbon resources. A survey of various techniques currently used for acquiring, processing and interpreting seismic data included a review of standard techniques and an update on new technologies.

PROBLEM ADDRESSED

Seismic processing and interpretation is extensively used by the majors and larger independents, but is often considered beyond the means of smaller independents. The recent advent of a number of low-cost seismic software programs to increase the speed and efficiency of processing, and assist the operator to interpret the data is a bonus to the independents operating in the Appalachian region. The workshop focused on learning how to plan and understand seismic data, and what software applications are available and how to use them.

KEY WORDS:

Acoustic Impedance; Coherency; Deconvolution; Horizon Attributes; Multi-component Seismic; Seismic Acquisition, Imaging and Processing

SPEAKERS

Dr. Bruce Hart, McGill University

TECHNOLOGY OVERVIEW

In today's rapidly expanding technology market, the key for independents in understanding and interpreting geology is to go Digital. The number of new, improved and advanced seismic processing and interpretation methods may be bewildering to the independent, but the one clear direction is that all information will be easier to use because of advances in digital technology. A short basic review of the physical basis for seismic analysis begins with a model of how acoustic energy is reflected and used to identify structural and stratigraphic boundaries. The advantages of 3-D seismic rather than older 2-D seismic is emphasized. 

Seismic Surveys using P waves
The majority of seismic surveys performed in the past have concentrated on P waves. The introduction defined and illustrated a number of seismic terms including: acoustic impedance, velocity, density, amplitude, phase, frequency and bandwidth. A series of slides were used to show how P waves reflect from different structural and stratigraphic components. A final seismic image will be a record of all the individual reflections from a specific location. Not all changes in lithology imaged by seismic waves are associated with change in acoustic impedance. For example, changes in fluid content within a single lithology can cause different reflections. It is important to remember that in seismic images the changes observed are interfaces and not the direct properties of the stratigraphic layers themselves. Resolution of seismic data is proportional to the frequency content. High frequencies give better resolution results, just as broader bandwidths give cleaner images. The two fundamental controls on determining if a stratigraphic bed will be visible on seismic reflections are the bed thickness and the contrast of the acoustic impedance with the surrounding layers. The frequency content of seismic data affects both the resolution and the apparent seismic stratigraphic relationships. 

Acquisition and Processing
The methods used for acquisition and processing have a major impact on the final seismic image. Interpretation of seismic images should start with the design of the seismic survey, because no matter how good the processing, it cannot compensate for poor acquisition of data. Survey design needs to take into account; marine versus land grids, the signal to noise characteristics associated with the surface sediment, and environmental factors such as vegetation, animal life and urban or rural buildings. Permitting and land access is a major part of seismic survey planning. Seismic acquisition is often a compromise between what is desired and what can be afforded. 

Seismic processing follows both normal moveout (NMO) to correct effects of separation between the receiver and the source on the arrival time of reflections and dip moveout (DMO), which corrects the difference in the arrival times or travel times of reflected waves from two offset locations, and accounts for dipping reflections. Deconvolution is the reprocessing method that improves temporal resolution. A number of new algorithms are available to apply deconvolution to seismic data. Seismic migration compensates for the distortion introduced by wave propagation and acquisition geometry. Migration is applied after stacking the data, and recently prestack migration has been developed for complex geological structures. Examples and methods of migration and prestacking are illustrated in detail. 

Interpretation 
It's important to have a clear understanding of the purpose of seismic interpretation, as it changes from project to project and over time. Knowledge of the software capabilities available and how these can be applied is necessary to achieve the desired end product. In basic interpretation, obtaining a "big picture" of an area is useful to put constraints on the broad-scale structural setting. Certain interpretation problems are common to particular areas, such as steeply dipping strata in mountainous regions. Complex faulting can be misleading, particularly at great depth. Digital data offer great benefits over paper seismic traces, including the ability to manipulate the data, flatten curves, change scales and color displays, integrate map data with log data, and try various post-stacking processing methods.

Advantages of 3-D Seismic Data
Although 2-D seismic data are still used, and reprocessing technology has made it possible to use old data, most projects will benefit from initial 3-D seismic survey technologies. 3-D seismic provides more complete surface and subsurface coverage, and allows for better visualization. Computer analysis of 3-D seismic data allows for multiple viewing methods; cubes, slices, stacked sequences and vertical transects. Horizontal slices or amplitude maps can only be obtained from 3-D data and are useful to show lateral variations in lithology, porosity, fluid content, thickness or geological features. Modeling and reservoir simulations are dependent on 3-D data.

Interpretation: Advanced Methods
Seismic attributes are a derivative of basic seismic measurements of geometric, kinematic, dynamic or statistical features. Amplitude images can be used to show faulting between multiple horizons, through changes in lithology, fluid continent, porosity or bed thickness. Complex trace attributes are based on reflection strength and are used to interpret instantaneous phases, which are independent of amplitude. Instantaneous phase use is valuable in looking at continuity of units, faults and picking horizons and subtle changes in waveform. Several classification schemes for seismic attributes issues were discussed: pre-stack vs. post stack, derived from data or interpretations, derived from complex trace or other interpretations, derived on a sample-by-sample basis or does the attribute represent a single interval property.

Correlation methods depend on linear, non-linear, single variable or multi-variate regression; geostatistics including co-kriging; and artificial intelligence using neural networks and fuzzy logic. Quantitative attribute analysis may be ported directly to simulators and can give insights into geology, if the data input is high quality seismic, and the log data have reasonable correlations between well and seismic data. Inversion techniques were developed to derive rock properties (acoustic impedance, velocity, porosity) from seismic data. A number of different inversion algorithms were illustrated. 

Multi-Component Seismic
Multi-component seismic uses data collected by the generation of both P and S waves. Some rock bodies are invisible to P waves but may be imaged by S waves. Multi-component seismic can also be useful in fracture identification. Multi-component seismic surveys involve using P wave sources and geophones together, and S wave sources and geophones together, and may record converted wave modes. 

Coherency
Coherency relies on observation of events that are similar or "coherent" on each side of a fault, but where the traces are different (low coherency) from one side of the fault to the other. By quantifying the coherency, it is possible to identify faults and other structural or stratigraphic features. The coherency approach was originally developed by Amoco and spun off as Coherence Technology Corporation. Now many software and seismic processing companies have developed variations of the method. 

Horizon Attributes
Surface- related attributes fall into three main categories: surface-associated, surface-rendered and surface-derived or horizon attributes. After the main faults and structural features have been identified, there may remain areas that cannot be defined. Horizon attributes can be used to locate these subtle structures that may affect production. Several specific software packages are available to interpret horizon attribute curvature and illustrate relationships. 

Case Studies
Several examples of the uses and interpretation technologies for 3-D seismic were introduced and discussed. The Cretaceous tight-gas sandstones of the Mesaverde Group in New Mexico illustrate a case where natural fractures play an important role in enhancing permeability. Interpretation problems in the Mesaverde included poor data quality, complex stratigraphy, lack of sonic logs, no checkshot surveys, and a focus on structure. The Mesaverde case study showed that subtle structures may be identified using various horizon attributes. In these tight-gas reservoirs, subtle structures may be associated with enhanced permeability or "sweet spots." 

A second case study discussed application in the Red River formation in the Williston Basin of North and South Dakota and Montana. Questions on the porosity distribution caused major problems in determining where to drill new wells. An interval-based approach to seismic attributes was used to image the porosity relationships. Attributes were picked to overcome deficiencies in the poorly understood log-seismic ties in the middle Red River formation. Fluid flow along fracture systems due to dolomitization controlled porosity. This resulted in use of seismic attributes to image diagenetic systems. Diagenetic interpretation from seismic data is new, and it is important to be sure that all statistical, geophysical, geological and engineering aspects are in agreement. 

Conclusions
The keys to success with 3-D seismic are: 1) good quality data, 2) an integrated, accurate database, 3) multidisciplinary integration from acquisition planning to reservoir management, 4) clear understanding of the capabilities and limitations of the methods and software used, and 5) insight— asking the right questions.

CONNECTIONS:

Dr.Bruce Hart
McGill University
3450 University
Montreal, QC H3A 2A7 Canada
Phone: 514-398-3677
E-mail: hart@eps.mcgill.ca

For information on PTTC’s Appalachian Region and its activities contact:

Douglas G. Patchen, Program Director
West Virginia University, Appalachian Basin Regional Lead Organization
P.O. Box 6064, Evansdale Drive, Morgantown, WV 26506-6064
Voice: (304) 293-2867 ext. 5443; Fax: (304) 293-7822
Email: dpatch@wvunrcce.nrcce.wvu.edu 

Disclaimer: No specific application of products or services is endorsed by PTTC. Reasonable steps are taken to ensure the reliability of sources for information that PTTC disseminates; individuals and institutions are solely responsible for the consequences of its use.

The not-for-profit Petroleum Technology Transfer Council is funded primarily by the US Department of Energy’s Office of Fossil Energy, with additional funding from universities, state geological surveys, several state governments, and industry donations.

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