No abstract

Micro-resistivity borehole image logs are well-established tools of geologist and reservoir engineers. These data are used for detailed reservoir description, providing high-resolution structural and sedimentological data. For thinly laminated turbidite sequences, they are often the only practical method of determining the distribution of net pay thickness in the absence of whole core data. Additionally, micro-resistivity images are used to help select intervals for formation testing and perforation. The increasing use of oil and synthetic oil-base mud systems to reduce drilling risks and improve drilling efficiency has created an environment that prohibited the use of conventional micro-resistivity imaging devices. Thus, it was imperative to develop a new micro-resistivity imaging technology for oil-based mud systems. This paper summarizes the development and successful application of a new oil-base micro-resistivity imager (EARTH ImagerSM) that brings well-accepted resolution and formation response characteristics of conventional micro-resistivity imaging technology to the non-conductive drilling mud systems. Combining the EARTH Imager with advanced open-hole logging instruments, such as the multi-component induction log (3D ExplorerSM), significantly improves petrophysical evaluation of thinly bedded sand-shale sequences. The interpretation model is built on a combination of high-resolution information from borehole image logs and the 3D Explorer horizontal and vertical resistivity data. These data are used in the Laminated Shaly Sand Analysis (LSSASM) petrophysical model to determine laminar sand resistivity, hydrocarbon saturation, and net sand pay. In our experience, such an approach provides a volumetrically balanced system that is highly reliable for predicting the production potential of an exploration well, a critical step when allocating resources for new development projects. Introduction As shallow-water hydrocarbon producing areas are becoming fully exploited, the frontiers of exploration are being pushed further and further into deepwater. Recent exploration efforts have focused on the deep marine turbidite sands with potentially huge hydrocarbon reserves. Numerous deepwater discoveries have been made in basins around the world as the exploration pace has quickened. The petroleum industry has demonstrated that these deepwater sands are excellent reservoirs capable of sustaining high production rates, thus dramatically increasing the economics for deepwater projects. Consequently, many E&P companies have elected to move into deepwater as rapidly as technology allows. The high-resolution borehole images are one of the most important tools for interpretation of deepwater sediments. The information derived from images is typically used for deepwater channel processes characterization, litho-facies determination, and vertical facies successions (channel stacking pattern). Furthermore, high-resolution borehole image data are routinely used to evaluate thinly bedded reservoirs, especially in the absence of core data. Borehole imaging does not replace outcrop or conventional core information, but in many cases is the glue that links core and outcrop data to the producing field. However, in today's economic environment where outcrop studies and conventional coring is considered an expensive luxury, borehole image data becomes the best tool and in many cases is the only data available for the interpretation of deepwater sediments. The science of borehole data collection and interpretation has been constantly advancing with many exciting improvements in recent years. Prensky (1999) provides an excellent bibliography of borehole imaging. Lovell et al., (1999) and Thompson (2000) document the main developments and applications to present. Lofts and Bourke (1999) detail the quality control necessary for interpretation of such images. The growing popularity of oil-based mud systems has hitherto provided an environment that precluded the use of conventional micro-resistivity borehole imaging technology. Economics and drilling considerations associated with using oil-based mud often outweigh the benefits gained by running micro-resistivity-imaging tools. Consequently, high-resolution analysis of thinly bedded deepwater reservoirs in the absence of core data becomes a major issue.

Interpretation for unconventional resources introduces a broad range of issues and objectives that are markedly different from those encountered when interpreting for conventional plays. There are of course many commonalities. Structural interpretation is still a strong driver, particularly to assist in geosteering horizontal wells with long extended reach. Structural attributes can also aid the analysis of the stress field and can inform the interpretation of microseismic data.Beyond this, however, there's a greater prize to be pursued: characterization of the unconventional reservoir with a goal of optimizing field development. Given the size of reserves that are involved and the magnitude of the capital investment, enhancing the efficiency of reservoir development through early and ongoing reservoir characterization can result in enormous financial gains and economic returns.Industry is still at an early stage in understanding how the key characteristics of an unconventional reservoir are manifested in the seismic domain and how the relevant information can be extracted from a 3D seismic data set. Intuitively, the key variables that characterize an unconventional reservoir can be identified and listed: total organic content, hydrocarbon filled porosity, permeability, presence or absence of open fractures, formation brittleness, formation stress, fluid properties, and lateral heterogeneity of the reservoir.Seismic attribute analysis offers the promise of providing insight on these properties. This would have a major economic impact in evaluating unconventional plays in the exploration phase and in ranking areas to drill in the development phase. Many operators are testing this approach over their acreage, but the accuracy that's needed is high. These reservoirs have low porosity and permeability. A variation of just 1 p.u. (porosity unit) in many cases can mark the difference between an economic and uneconomic well. This is the level of accuracy we must seek in our seismic prognosis.This special section of Interpretation presents a set of papers that shows where we are in the pursuit of this goal. The first two papers outline interpretation workflows for unconventional resources. Rebec et al. discuss the use of seismic data to reduce risk and improve production in unconventional plays. This requires careful preplanning based on the nature of the play, acquiring the right seismic program, processing the seismic data correctly, extracting the optimum information and then transforming the information into business value. The authors discuss these criteria and focus on extracting the optimum information with examples from the Marcellus and Niobrara plays.Leiceaga et al. address how integration of prestack seismic, rock physics, horizontal drilling, and hydraulic fracture monitoring may be used to help evaluate hydrocarbon production capacity in unconventional plays such as tight or shale formations. The workflow presented in this paper demonstrates how several pieces of the geoscience puzzle may be fit together to ...

No abstract

No abstract