A research borehole‐geophysical logging program was implemented to assess specific yield, aquifer mineralogy, and water resistivity more accurately and economically than can be done using conventional aquifer testing and coring procedures. The logging program was part of the Ground‐Water Research Project for Abu Dhabi Emirate. A method of determining specific yield using data from a thermal decay‐time (TDT) log was developed and tested. This technique relates the capture cross section of the fluid in the invaded zone to specific yield. A second new method uses data from density and neutron logs in a program “LOGAN2” to determine specific yield. Results from both methods were compared to the specific yield derived from the neutron log as well as a specific yield determined by a complex analysis of data from a set of research borehole‐geophysical logs, including a gamma‐gamma log for density, neutron, sonic, gamma‐ray, induction, microresistivity, photoelectric, caliper, and spontaneous‐potential logs. The agreement was good. A method of computer‐assisted interpretation of mineralogy was developed by correlating results of direct examination of the mineralogy of sidewall cores with data from a nuclear activated spectral‐gamma log (GLT). The GLT log allows the mineralogy to be assessed in a comprehensive manner. These computer interpreted results were used to develop another method of computer‐assisted interpretation of holes logged not using the GLT. The second method was applied to the more than 50 other test holes that did not include GLT and TDT logs. Resistivity of the water in the formation was conceptualized using a dual‐water model, which is especially suited for clayey aquifers. Water resistivities were calculated by two methods—first using data from the suite of logs without the GLT and again using the data from the research suite of logs, which included the GLT. The agreement of calculated water resistivities was excellent

ingly. Data and properties derived from logs Were used to determine transmissivity and specific yield of aquifer materials.

In order to improve oil recovery from the main oil producing reservoir of an offshore Abu Dhabi field, two gas injection pilots have been tested. To explain their relative performances, a combination of classic tools (cores, electrical logs) and high-tech tools (DSI, FMI, CT-Scan) as well as 3D seismic have been used to further investigate the reservoir anisotropy in one of the pilot area. The logs indicate the presence of a fracture system. The full comprehensive core versus log calibration allows to extend the results found to the non cored intervals. The combination of the classic and high-tech tools leads to a better understanding of reservoir behaviour and heterogeneities. Introduction In order to improve the oil recovery from the Lower Arab Formation (D2), two gas injection pilots have been tested on a field offshore Abu Dhabi. One behaved as expected (Multidirection) while the second one (Figure 1) showed an unidirectional dolomitic layer D2a1 (2 to 5m thick). The data from three wells (Figure 1) have been used for the study in order to investigate:the cause of reservoir anisotropy in the second gas injection pilot, based on three well cores and logs analysis.why the reservoir top dolomitic layer does remain unswept after more than 20 years of oil production,the sharp contact between the top dolomitic layer (D2a1) and lowermost dolomitic one (D2a2), appearing as a stylolitic contact, with electrical facies image similar to the X Ray Core Tomography scan (CT scan) image. The available set of data consists in a Dipole Shear Imaging (DSI) log recorded in the side-track of the gas injector well and associated to three core-sponge; a Formation Micro Imager (FMI) log recorded in the side-track of a previous pilot oil producer; a set of conventional cores with an available High resolution Dipmeter Tool (HDT) log (recorded in 1984) in that latter well and a recently acquired 3D seismic. This paper describes the combined analysis and presents the results acquired for a better understanding of the reservoir behaviour and heterogeneities. Main Results Per Well Side-track of Gas Injector Well. The three sponge cores cut in this well have been described on site, the description is given on enclosed log (Figure 2). Cores observation. The main observed points are:a continuous lithological change from the anhydritic upper reservoir boundary to the top dolomitic D2a1 layer,the dolomite of the upper part of this layer (D2a1 Upper) is micro to finely crystalline, homogeneous with a content of secondary crystalline anhydrite at the base,the dolomite of the bottom part of this layer (D2a1 Lower) is finely crystalline, with less anhydrite content and heavily bioturbated,the sharp contact with the lowermost layer (D2a2) is underlain by a thin anhydrite streak (millimetric), this contact has been investigated with a X Ray Core Tomography scan (CT scan) analysis (Figure 3). Fractures are identifiable by an energy loss on one or more of the three types of acoustic energy detected with DSI. Permeable fractures exhibit an energy loss and a non-zero reflection coefficient on the Stoneley wave form. Main Results Per Well Side-track of Gas Injector Well. The three sponge cores cut in this well have been described on site, the description is given on enclosed log (Figure 2). Cores observation. The main observed points are:a continuous lithological change from the anhydritic upper reservoir boundary to the top dolomitic D2a1 layer,the dolomite of the upper part of this layer (D2a1 Upper) is micro to finely crystalline, homogeneous with a content of secondary crystalline anhydrite at the base,the dolomite of the bottom part of this layer (D2a1 Lower) is finely crystalline, with less anhydrite content and heavily bioturbated,the sharp contact with the lowermost layer (D2a2) is underlain by a thin anhydrite streak (millimetric), this contact has been investigated with a X Ray Core Tomography scan (CT scan) analysis (Figure 3). Fractures are identifiable by an energy loss on one or more of the three types of acoustic energy detected with DSI. Permeable fractures exhibit an energy loss and a non-zero reflection coefficient on the Stoneley wave form. Side-track of Gas Injector Well. The three sponge cores cut in this well have been described on site, the description is given on enclosed log (Figure 2). Cores observation. The main observed points are:a continuous lithological change from the anhydritic upper reservoir boundary to the top dolomitic D2a1 layer,the dolomite of the upper part of this layer (D2a1 Upper) is micro to finely crystalline, homogeneous with a content of secondary crystalline anhydrite at the base,the dolomite of the bottom part of this layer (D2a1 Lower) is finely crystalline, with less anhydrite content and heavily bioturbated,the sharp contact with the lowermost layer (D2a2) is underlain by a thin anhydrite streak (millimetric), this contact has been investigated with a X Ray Core Tomography scan (CT scan) analysis (Figure 3). Fractures are identifiable by an energy loss on one or more of the three types of acoustic energy detected with DSI. Permeable fractures exhibit an energy loss and a non-zero reflection coefficient on the Stoneley wave form. Cores observation. The main observed points are:a continuous lithological change from the anhydritic upper reservoir boundary to the top dolomitic D2a1 layer,the dolomite of the upper part of this layer (D2a1 Upper) is micro to finely crystalline, homogeneous with a content of secondary crystalline anhydrite at the base,the dolomite of the bottom part of this layer (D2a1 Lower) is finely crystalline, with less anhydrite content and heavily bioturbated,the sharp contact with the lowermost layer (D2a2) is underlain by a thin anhydrite streak (millimetric), this contact has been investigated with a X Ray Core Tomography scan (CT scan) analysis (Figure 3). Fractures are identifiable by an energy loss on one or more of the three types of acoustic energy detected with DSI. Permeable fractures exhibit an energy loss and a non-zero reflection coefficient on the Stoneley wave form.

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TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractObtaining the water and hydrocarbon saturations in any reservoir are one of the main applications of many logging instruments. Resistivity has been used with relative success in many fields and can be considered the main open-hole "saturation" measurement, even though true formation resistivity remains elusive. Pulsed neutron capture is the basic cased-hole "saturation" measurement when formation water salinity is known and high enough. While either one has its own limitations, they often agree well enough that they reinforce the user confidence in their respective accuracy. Thus, they are generally considered adequate for reservoir management decisions.Occasionally, acquiring and comparing a large number of different measurements that respond to fluid distribution in the formation shows that two measurements dose not give the same answer. As a result, Petrophysicists face the task of reconciling and explaining those discrepancies to extract additional and valuable information.In this paper, we review the principles, advantages and limitations of a certain number of measurements acquired in both open and cased hole. We briefly review how data was handled in the past and the way it is handled today. We then review how discrepancies are reconciled today and make suggestions and recommendations as to which measurements are the most appropriate for various types of environments.In the last part of the paper, we are suggesting new ways to acquire, process and interpret log data. Logs free of environmental effects will be obtained through the acquisition of auxiliary measurements that define the Wellbore environment accurately. Models are used to evaluate and correct for the environmental variations that are not resolved by in-built sensors. Tool planners are expanded to become true artificial experts that recommend the right measurements for a given formation and borehole environment. In addition, the uncertainty on the logs, parameters and models will be propagated to the output uncertainty in a meaningful and representative manner.