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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.

In exploration wells in shallow waters of Mexico, the challenge of reducing drilling time and enhancing efficiency of well construction had become a problem on a daily basis. The continued use and success of Casing while Drilling (CwD) led the operator and service companies to embark upon a more ambitious project. Using the learning curve of previous 20″ CwD conductor sections, the first 34″ PDC drillable drill bit was designed and the first Casing Running Tool (CRT) for 30″ casing was utilized. These tools were used to apply the technology in the conductor sections of wells targeting Mesozoic formations. A technical feasibility study was performed by the operator and service companies involved to analyze the viability of executing this whilst creating new products. This saw the implementation of CwD using 30″ casing, an integral drilling system using casing as the drill string and a PDC drillable bit that allows drilling and casing of the section to take place simultaneously and eliminates the need to assemble a 36″ drilling BHA and, subsequently run casing. Once the CwD BHA (Casing + Drillable drill bit) reaches the final depth of the section, the hole is already cased and ready to cement. This challenged the service companies' engineering departments to develop the custom made tools for the application. In the first well, the original plan was to drill the 30″ section using a 36″ roller cone bit, drilling from sea bed (+/-78m) to 250 mts. This was the candidate well that the operator chose to utilize an ″unconventional″ drilling system to ensure reaching TD in a single run prior to cementing the casing. The 30″ × 34″ conductor section was drilled and cased at a depth of 256 meters, drilling a total of 178 meters with the PDC drillable drill bit (4 blades + 19 mm cutters) in 9:52 hrs., with an average rate of penetration (ROP) of 18.04 m/hr., and then preparations for cementing the 30″casing began. This entire operation represented a 26.3% time reduction compared with a conventional drilling operation This document will show the methodology and technology used in Mexico Marine Exploratory fields to reduce and mitigate the risk of not setting the casing at TD, focusing on the pre-planning stage, proper bit selection, Torque & Drag (T&D) analysis, casing fatigue life analysis and the use of new technology with a high success ratio on the operations in order to add value and ensure the customer' satisfaction.

This work is the result of authors' experience in complex reservoirs such as the calcitic-lithic sandstones of the Chicontepec Formation, in the Chipontepec Channel Basin. These rocks, highly reactive to acids, present problems of low permeability; they are often fractured but production decline rapidly in time. The diagenesis experienced by these reservoirs is very complicated because the large amount of carbonate lithics, igneous and metamorphic components present, which can be mixed with detrital clays and dissolution of fossils (moldic porosity). The Chicontepec Formation is a turbidite sequence deposited in shallow waters in a submarine canyon with submarine fans, benthic foraminifera, some charred plant remains, and graded and convolute cross-lamination. It is composed by alternating well cemented calcareous-clayey-sandstones, and dark gray calcareous shale. It exhibits conglomerate horizons, consisting of chert and platform limestone clasts. Petrographically it is composed by very fine grained to middle and, occasionally, course litarenite; consisting of carbonate lithic (mudstone), monocrystalline quartz, plagioclase (sericitized) and a minor lithic igneous, metamorphic, silt and shale components. The main authigenic cements are kaolinite, chlorite, calcite, ankerite and interstratified I/S. The facies described from core samples were adjusted with microfacies obtained from thin sections where permeabilities ranging 0.1 to 400 milidarcy, and porosities between 4 to 15% and occasionally 20% could be differentiated. The described type of porosity is mainly intergranular, with some intragranular and moldic porosity. The analysis of high technology logs, such as magnetic resonance and image logs, permitted us facies modeling by using a 3D multivariate analysis of Coates permeability, effective porosity, shale volume and volume of irreducible water to represent facies described in the analyzed core samples and to obtain an integrated Petrophysical-Geological model. The study of these diagenetic facies allowed us to predict which of the electro-facies were susceptible to high reactivity and select the best candidates for stimulation.