The value of the continuing integration of logging-while-drilling (LWD) and directional drilling processes has been more prominent in the current economic environment in terms of optimizing field development costs by means of precise well placement, as well as improved reservoir characterization and drilling performance in real time. A successful horizontal drain was drilled in an undeveloped Reservoir A for the first time in an offshore carbonate sequence, using advanced LWD acoustic and high-resolution microresistivity sensors. The well plan required maximizing the exposure of the most porous body in a thinner sublayer. This sublayer lies directly over a large, developed carbonate reservoir as part of the Upper Jurassic Carbonate sequence located offshore Abu Dhabi. The flow test results during the drillstem test (DST) operation for the first appraisal well in the target reservoir produced at a rate that was greater than expected. Production log data were acquired and integrated with the LWD microresistivity image interpretation. In addition, in this environment, the inferred Rt and Rxo measurements from the LWD azimuthal focused resistivity tool were shown to be more reliable than conventional electromagnetic wave resistivity measurements, which are prone to exhibiting significant polarization, anisotropy, and bed boundary effects. Lessons learned from the first appraisal well in Reservoir A for reservoir characterization and flow unit identification were used and implemented in the planning and successful delivery of the future horizontal wells. Unlike the other reservoir subunits that are deposited within the same sequence, the field development strategy for these undeveloped reservoirs has been under review based on the recent data. The field development strategy used enhancements in well placement, formation evaluation, and production technologies, including extended reach horizontal wells, with maximized reservoir exposure in the sweetest zones, to compensate for the poor petrophysical character and low oil mobility. This case study presents insights into the advanced geosteering and multidisciplinary reservoir characterization processes along these successful horizontal drains drilled in undeveloped Reservoir A and the future horizontal wells. It also demonstrates the integration between the geological and petrophysical interpretation and the use of acoustic measurements and high-resolution microresistivity imaging. This combination has enhanced the understanding of Reservoir A in terms of the unexpected production performance and helped optimize efforts for the future field development plan.

With the popularity of nonconductive drilling fluid (NCM), a new generation electrical borehole imaging tool that uses megahertz logging frequencies is developed to decrease the capacitance of the NCM for acquisition of high-resolution images. At this frequency range, both electrical conductivity and dielectric permittivity of the subsurface dictate the logging measurement. This challenges our understanding of the tool response in terms of resistivity contrast and affects the algorithms in the geologic interpretation software that use the resistivity image value. For example, open vugs filled with NCM can appear resistive on images and invalidate the basic assumptions of existing secondary porosity quantification software that open vugs are filled with conductive mud (since they were developed for water-based mud). A new laboratory device that features the same logging frequency, as the logging tool has been developed to assess the new algorithms for quantitative interpretation. The device was used to investigate images of secondary porosity features acquired in NCM in controlled laboratory conditions. It is demonstrated that for effective analysis of fluid-filled vugs, a resistivity image is not sufficient to count the NCM-filled vuggy area. A new post processing method is introduced by combining the effects of resistivity and dielectric permittivity and generating a new image called the rock Hayman factor image. On the Hayman factor image, it is possible to differentiate fluid-filled vugs from cemented vugs. Based on this analysis, a new NCM vuggy formation characterization workflow is proposed. The workflow was applied to a downhole case study for a vuggy carbonate reservoir. The Hayman factor image agrees with the resistivity log/image in identifying oil, transition, and water zones in the well, and it shows enhanced heterogeneous texture patterns in different zones. Software incorporating Otsu's method was capable of discriminating between the continuous rock background phase and heterogeneous phase by varying input parameters and was used to test the image feature contrast of a resistivity image logged in oil-base mud (OBM) by using the conventional heterogeneity analysis method and the new Hayman factor image. Interestingly, when the OBM-logged resistivity image is input, no vugs were found in the area where core photographs indicate vugs are present. However, running the software on the Hayman factor image can characterize vugs with a frequency that matches well with the core photographs. This shows that the Hayman factor image has improved feature contrast compared with the original resistivity image. The new postprocessing Hayman factor image is designed to quantify rock resistivity and the dielectric permittivity effect. A new vug characterization workflow using this new image is proposed for NCM environment secondary porosity quantification.

TX 75083-3836, U.S.A., fax ϩ1-972-952-9435understand not only the geological characteristics, but also the variations in reservoir properties within seemingly similar facies.This work presents the first account of interpretation based on a new technology for OBM formation imaging, with innovative inversion techniques. This also serves as a roadmap for carbonate reservoir characterization in Middle East in the wells drilled with OBM. Also, the encouraging results provide a trendsetting example of applications of this new technology.

The lower cretaceous carbonate sequence, offshore Abu Dhabi is represented by the third to forth order sequences. Limestone is the dominant lithology for this group of ramp to intrashelf basin sediments. Fracture intensity and density vary vertically along the sequences, controlled by rock texture contrast. Dense layers are heavily fractured compared to the porous bodies throughout these Formations. Two dominant sets of fractures are observed throughout the field, NW-SE and NNE-SSW. Historical well test data indicate strong preferential flow in that same direction compared to less flow in the NW-SE trend (anisotropic drainage behavior). The objective of this study is to demonstrate the capabilities of simultaneously acquired near and far field borehole sonic reflection logging measurements to characterize the present fractures along a dedicated horizontal drain for data gathering. Borehole image log interpretation and other well logs are integrated. Understanding fracture systems using resistivity imaging solely could be challenging due to the limited depth of investigation of the measurement (at the well location). Well trajectory, (open) fracture density and orientation can cause uncertainties in the number of fractures that intersect the borehole. Primary fractures could be abundant away from the borehole but still contributing to flow and reservoir pressure behavior. With a unique extended depth of investigation as well as azimuthal sensitivity, dipole sonic imaging is able to reach tens of meters into the formation and provide fracture intensity and extension information in the far field. A new scale of data integration using near field measurements from monopole sonic imaging, Stoneley wave reflectivity analysis and borehole image interpretation for a comprehensive fractures characterization is accomplished. A set of structural incidents could be detected tens of feet away from the borehole, some seemed to be extending towards the borehole wall itself as seen by the Stoneley reflectivity and the sonic-resistivity borehole imagers. Open fractures are clearly characterized in terms of orientation and aperture, extension inside the reservoir could be recognized, small-scale fractures near the borehole could be discriminated, as well as the closed ones, in addition to the dense stylolite markers. Comparisons with offset cores, seismic and offset well data shows a range of coherence. Most of the fracture clusters were observed at the stylolite boundaries. The main orientation of these fractures are consistent with the present day in-situ stress orientation. The integration of data with respect to resistivity, sonic borehole image and Stoneley wave data from sonic monopole processing are in coherence. Far-field dipole shear sonic imaging adds valuable information to investigate the major carbonate reservoir structural incidents away from the borehole. The value is maximized by integration with the high-resolution borehole image that drew some conclusions on the presence of different sets of fractures distribution and their nature.

The undeveloped sublayers of the prolific offshore Arab reservoir were recently targeted for appraisal drilling, aligning with the ever-increasing efforts to expand production and book new reserves. The first extended reach horizontal well was drilled in this field to evaluate the economic potential of four different reservoir sublayers. Reservoir characterization and the evaluation of lateral permeability changes were the primary objectives for these low permeability layers. Maximizing reservoir contact while maintaining minimum borehole tortuosity presented substantial geosteering challenges. Another challenge is that the bottomhole assembly (BHA) must be free from radioactive chemical sources. A well placement workflow was developed that honors the structural geological setting, based on the existing field knowledge and offset petrophysical data. The optimized BHA consists of a point-the-bit rotary steerable system (RSS) and logging-while-drilling (LWD) sensors. These LWD sensors include high-resolution microresistivity imaging, laterolog resistivity, azimuthal multipole acoustic, nuclear magnetic resonance (NMR), ultrasonic calliper, and near-bit azimuthal gamma ray sensors. High-resolution microresistivity imaging and the near-bit azimuthal gamma ray sensor were used to geosteer in the thin reservoir subunits and to facilitate fracture identification. NMR was used to help remain in sweet zones in real time and to provide pore size distribution, based on T1 measurements for permeability evaluation. Acoustic and high-resolution image data were used to derive empirical permeabilities. The 8,000-ft horizontal section was successfully geosteered with 100% reservoir contact, tapping into four thin reservoir sublayers. Real-time high-resolution microresistivity images, dip picks, and near-bit azimuthal gamma ray data helped to maintain the wellbore attitude parallel to the stratigraphy within each sublayer; they also facilitated a smooth transition from one sublayer to the next with minimum borehole tortuosity, aided by the point-the-bit RSS and at-bit inclination measurements. Fracture evaluation from high-resolution images, NMR, acoustic, and image-based permeabilities are integrated with production log results to enable a better understanding of the field, to benchmark flow unit identification in these undeveloped reservoirs, and to optimize future geosteering and petrophysical data acquisition requirements. The traditional reactive geosteering concept is challenged by placing the 8,000-ft extended reach section in four different sublayers that are as thin as 3 ft true stratigraphic thickness (TST) without penetrating any boundaries. The multidisciplinary approach helped to assess the economic potential of these undeveloped layers within the local reservoir sector and to formulate plans for a future field development program.