The economic feasibility of a well drilled in tight carbonates is extremely dependent on the level of fracture permeability; hard and dense carbonate formations may not be considered as net pay without the presence of fractures. The evaluation of fractures is a key to reservoir effectiveness characterization for well drilling, completion, development and stimulation of fractured reservoirs. While knowledge of the geological conditions and regional stress is helpful to estimate the characteristics of the natural fracture system in a given reservoir, the true extent of the natural open fracture system in any specific location is typically unknown. Several methods are available to the industry to identify natural fractures near the wellbore, including acoustic and resistivity image logs. In some cases, the poor-quality results of these techniques do not provide reliable information and such data cannot be available in all the wells. When minor downhole losses are accurately detected, it is possible to locate and characterize the natural open fractures intersected by the drill bit while drilling operations. The differential flow (Flow-out minus Flow-in) and the Active Volume System are continually monitored during drilling and integrated with drilling and hydraulic parameters. These readings are processed in a computer-based, data-acquisition system to form a compensated delta-flow signal that identifies the occurrence of downhole fluid losses. The differential flow is measured accurately through a dedicated Coriolis type flow-meter with a Limit Of Detection up to 10 l/min. By accurately detecting and measuring the downhole micro-losses instantaneously at the surface, the responses would be compared to predefined models for fracture characterization; that enables identification of different types of fractures (open natural, induced fractures). The system can detect very fine micro-fractures that might not be visible with wireline images; fracture density plots can then be created to highlight the fracture concentration along the well. Drilling deep wells in Kuwait is challenging due to high pressure, high-temperature formations, with the Bottom Hole Pressure of +15kpsi and Bottom Hole Temperature of +150 Centigrade degrees. In conventional surface systems, the loss detection relies on the Active Volume System and the Paddle type Flow-out sensor; however, these systems usually fail to identify the minor mud losses associated to open fractures. Especially for active pits with a big surface, it is almost impossible to identify few millimetres of mud level decrease and during fluid transfers, mud conditioning will make the job even more difficult to identify minor losses. With flow paddle type of sensors, the flow out information is not displayed as a calibrated value but rather as a percentage of full scale, which can be difficult to interpret. Instead, dedicated Coriolis type flowmeters properly installed, can identify flow rate changes accurately, regardless of any transfer of mud, water or diesel between pits. By applying this technique, it is possible to identify fractures while drilling in different types of wells, such as vertical, highly deviated and horizontal. The data were validated initially through core and image logs and further applied in next drilling campaigns.

This paper presents a methodology which allows performing a real time characterization of the conductive natural fractures permeability intercepted by the bit while drilling. Such fractures are detected by monitoring continuously flowing from the wellbore into surrounding formations and the mud losses at the rig-site using flow-meters measuring both the ingoing and the outgoing mud flow. Moreover, when drilling naturally fractured reservoirs, mud loss data provide one of the most effective means to assess the existence of conductive fractures intercepting the wellbore and therefore to identify potentially producing intervals. The patterns in the variations of these volumes are analyzed to identify open fractures. The advanced Flowmeter has increased the resolution of the mud flow measurements. It has enabled the authors to assess the flow quantitatively and relate mud flow anomalies with the presence of open fractures down hole in the trial exploratory well. The mud flow anomalies were validated with surface drilling parameters and gas indications. It was observed that the open fractures were associated with increase in torque and gas indication. The mud flow anomalies also provide crucial information for early kick or losses detection in high pressure gas wells because a better accuracy and a quicker response in detecting kicks and losses can be achieved by monitoring the changes of the mud flow rate by using flow meters measuring the inflow and the outflow mud rate, respectively. Method and Theory The most commonly used techniques to detect the mud losses consist in monitoring the level of the mud pits with acoustic, floating sensors and/or using paddles set inside the flow line that measure the return mud flow rate with a small degree of accuracy. The traditional Flowmeter provides a simple qualitative fluctuation in mud flow. In contrast this advanced Flowmeter works on the principle of converting mudflow out in to an analog signal which represents the volume of mud.

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While drilling through a reservoir, a lot of valuable information can be obtained from mud logging to support formation evaluation. Field data will help wellsite geologists, petrophysicist and reservoir engineers to predict reservoir quality, fluid contacts and reservoir permeability based on formation gases detected while drilling. This study discusses some examples from exploratory wells that have recently been drilled in Kuwait. Gas readings were recorded while drilling through deep Jurassic formations to evaluate hydrocarbon content using Advanced Gas Chromatography. The primary components of the system utilized are: a constant volume gas extractor, a gas sample flow control system, and a high resolution chromatographic system. To interpret the findings Gas readings are monitored by a complex system which provides real-time continuous measurements of the concentration of formation gases from very light components such as methane, to heavy components such as C6, C7 and C8 hydrocarbon species, comprising n-hexane, n-heptane, n-octane, benzene and toluene. Formation gas is considered as the first indication of a reservoir's fluid characterization and reflects the extent of the productivity of the well. Geochemical ratios and equations can enhance the interpretation of field data and give the first indication of zones of interest that need further evaluation. Dedicated flowmeter sensors (Coriolis) utilized to evaluate formation fractures while drilling. The Delta Flow trend versus time is characteristic of the type of losses and consequently of the downhole fractures. Geochemical ratios are plotted against depth and lithology to determine fluid type, contacts, fractures and dolomitization. For this purpose Well-Site Geochemical Package services, including X-Ray Fluorescence (XRF) and X-Ray Diffraction (XRD) workflow at rig site was also applied in of the wells. The analysis is based on measuring major and minor chemical mineralogy and elements of the drilled cuttings. This has helped in better quantitative assessment of different facies such as limestone, dolomite, shale etc., and providing a better control on geological model update while drilling the well. To take advantage of the field data, advanced mudlogging data are plotted on a depth log, which can be easily integrated with other data (post well data).

The Hith and Gotnia Formations in Kuwait were considered to only be acting as seals for the early Jurassic hydrocarbon bearing reservoirs. However, recent hydrocarbon discovery within the Gotnia Formation has proven that they have reservoir potential as well. Due to High Pressure-High Temperature (HPHT) conditions of these formations, casing is set immediately after drilling, thus limiting open hole data acquisition. To overcome this problem we deployed a single mass spectrometry service for advanced gas analysis to understand and characterize the fluid variations within the Hith and Gotnia Formations. Two mass spectrometers, for gas in and gas out detection, were connected to constant volume degassers in the suction pit and shaker house, respectively. First, the dynamic oil based mud (OBM) discriminator differentiated OBM contamination and subsequently the unique ‘real-time’ algorithms quantified concentrations of formation hydrocarbons. The formations under evaluation were divided into 3 major geochemical zones based on acquired gas data. These geochemical zones were marked by changes in mud gas response and were closely linked to lithological properties, each lithology type having a distinct gas signature. The Hith Formation consists of thinly interbedded anhydrite and limestone and comprises the first geochemical zone. With low gas response, gas ratios point to a potential oil fluid type although the formation is likely unproductive due to low permeability and high water content. The four halite intervals within the Gotnia Formation were grouped together as the second geochemical zone, having no production potential due to their low porosity and permeability. They behave as a seal to the hydrocarbons in the interbedded anhydrite-limestone intervals. The three anhydrite plus limestone intervals within the Gotnia Formation belong to the third geochemical zone. Comparison of the oil signatures in these intervals revealed a decrease in fluid density from top to bottom. The different fluid density within each interval and the sealing efficiency of the interbedded halite suggest that there is no direct fluid communication between the individual anhydrite cycles. This paper covers in details the response and interpretation of the gas signatures in each zone.