First Break - Volume 20, Issue 11, 2002

Gavin Hills-Jones, director, business development in the UK office of Geotrace Technologies, describes how the company is bringing new resolution to North Sea data through an imaging technology first developed for processing US seismic data.

Thomas B. Espersen, Anthony Hardwick, Neil Ratnett, and John Sunderland explain why 2D seismic data of any vintage may prove invaluable in the outcome of newer 2D surveys focused on the same target area.

Weizhong Wang and Constantine Tsingas, PGS Geophysical, illustrate a new technique in seismic processing with particular benefit to the treatment of 4C data acquired in deep water ocean bottom surveys.

Luk Ikelle, project coordinator, outlines the objectives of the Center of Automated Seismic Processing, of which he is the director.

One of the problems of using seismic data to image the subsurface is that, if there is significant lateral variation in the overburden, standard time migration may image a reflector in the wrong location. This is obviously a problem if you have it in mind to drill a well into it. These days, it would be routine to apply a depth migration algorithm that can image the reflector in the right location, so long as the velocity field is correct. However, back in the 1980s it was common to try to estimate the size of the time-migration mislocation using image ray construction, and this method is still sometimes used today. First Break asked Rodney Calvert of Shell International to explain why this is not a good idea.

The seismic interpreter often has access to large amounts of data, in particular in mature and partially mature basins. Or- ganizing and interpreting the geological and geophysical data in a time and cost efficient fashion is a major challenge. Similarly, the unwritten requirement to be 'right' most of the time means that explorers are occupied in a constant search for means to reduce the risks in their prospects and developments.In addressing these challenges and objectives, a third issue arises, that is the large (and constantly expanding) array of commercial and proprietary technology-based 'interpretation tools' potentially available for use. The questions has thus become, 'What is the exploration problem/risk to be addressed?' and 'Which interpretation tool could be usefully applied to solve the problem?' The ultimate cost/benefit analysis of this process is the measurement of the impact of the technology on the overall understanding of the risk of the prospect or the development. These issues could be usefully addressed by an industry-wide survey of both successful and unsuccessful case histories of technology applications. It seems reasonable to surmise that unsuccessful applications of technology are only rarely published (possibly when the authors are approaching retirement?) Successes may be 'stored away' for reasons of competitive advantage. Most companies are unwilling to share 'cutting edge' technologies or processes which they perceive to give them a competitive advantage. Hence, the purpose of this article is twofold. Firstly, a brief review of some technology applications on a real, and as yet undrilled, North Sea prospect, and a qualitative assessment of their impact on the perceived risks. Secondly, the issue of value for money and the time-saving potential of new technologies is raised as a discussion point within the hydrocarbon exploration community, both within oil companies and the contractors who generate most of the technology. How do we measure the value of technology?

Introduction 4D (also known as time-lapse or repeat) seismic has in the past few years emerged as a significant technique for monitoring fluid movement within reservoirs. In recent years, an improved understanding of the petrophysics of the reservoir (e.g. Wang 2001) has enabled geoscientists to establish relationships between observed seismic attribute changes and corresponding rock property changes. Once it was established that such additional information could be extracted from surface seismic data (e.g. Lumley 1995, 2001), changes were made to seismic data processing sequences so as to better preserve relative amplitude changes, especially with regard to pre-stack differences between data vintage subsets. Monitoring of changes as diverse as temperature (as in the case of steam injection: Lumley 1995) and movement of fluid contacts have proved attainable and successful (Jack 1998). Previously, one of us (Jones & Baud 2001) demonstrated the potential of using a dense velocity estimate as a high-resolution tool for visualizing subtle changes not clearly discernable in the seismic amplitude response. (The success of such techniques depends to a large part on the data being correctly pre-stack migrated, so that all the diffraction energy is correctly collapsed.) In this work, we assess the potential of high resolution velocity as an indicator of reservoir change in the context of a 4D study (Jones & Folstad 2002).