No abstract

No abstract

Logging wells drilled in coalbed methane reservoirs (CBM) is a common practice in the industry. As a rule of thumb, the logging suite comprised of standard methods is run to identify coal layers for subsequent degasification. However, given the increased popularity of the commercial methane production from CBM reservoirs, the petrophysical data from standard methods is not sufficient to evaluate the productivity of deposits and to assess the effectiveness of such projects. The permeability of the coal matrix is usually non-existent. The natural fractures are key controlling factor for gas migration and the performance of a CBM reservoirs depends largely on this parameter. In this study formation microimager was used to identify fractured intervals and based on these results the most promising intervals were selected for further testing. The well testing of low permeability formations can be extremely difficult due to the long build-up times to achieve different flow regimes. This step can be optimized by deploying wireline formation tester to estimate the permeability of the coal layers in open hole. Innovative extended spacing dual packer configuration of the wireline formation tester was deployed to selectively test coal layers ranging from 1 to 9 m deposited at shallow depths of 200-900 m. Fragile nature of the coal seams often resulted in washouts, which presented some challenges while inflating the packers to isolate the interval. Several cycles of fluid pumping were performed followed by pressure build-up periods until the radial flow regime was observed. Data processing and monitoring was carried out in real-time allowing to obtain high quality data and to optimize the operations. Data acquired by formation microimager was used to perform facial analysis to determine depositional environment and to further aid in mapping the coal layers and for future well placement considerations. The knowledge about the depositional environment allows to predict the regions where coal layers are formed confined by the flooding areas. The geological setting of the coal basin is made up of many coal layers of varying thickness deposited at depths of tens to hundreds of meters. The application of an advanced logging suite comprising of formation microimager and wireline formation tester allowed to selectively test the most promising coal layers. All the measurements were carried out in open hole at a drilling stage.

Various techniques are used in industry to determine the reservoir connectivity. The rock-based methods such as seismic mapping and well-to-well correlations present some challenges in subsalt and salt overhang deposits. While fluid based methods such as pressure gradients are traditionally used to infer the lack of connectivity and oftentimes cannot confirm the presence of it. Recent advances in asphaltene science have made it possible to clarify asphaltene distribution mechanism in reservoir allowing to address reservoir connectivity. The asphaltene distribution in the reservoir is characterized by an equation-of-state (EoS) proposed by Flory, Huggins and Zuo. The classical approach of estimating an asphaltene gradient of the reservoir fluid involves acquiring downhole samples and performing laboratory analysis. However, since the asphaltene content is associated with the coloration of hydrocarbons, a method has been proposed to delineate the asphaltene gradient at reservoir conditions by measuring the color differences of formation fluid with depth using optical fluid analyzer. Integrating the color data from optical fluid analyzer with the proposed equation-of-state, it is possible to elucidate the connectivity of the individual layers. This paper presents the results of the well logging campaign conducted in the field located in Western Kazakhstan, where new oil deposits were discovered below the salt overhang in Triassic and Permo-Triassic sandstone formations. Several exploration wells were drilled in different blocks of the field. Advanced open hole logging suite comprised of standard logging methods, nuclear magnetic resonance and wireline formation tester was run in all the wells to characterize the reservoir. The wireline formation tester toolstring included an optical fluid analyzer module, which allowed to measure optical density values of an oil at different depths in each of the wells. The study shows how the asphaltene gradient of an oil column constructed from optical density data in conjunction with geological and petrophysical data can be used to delineate reservoir attribute such as lateral connectivity. The analysis confirmed the hypothesis on the lack of reservoir connectivity between the two blocks separated by faults. The prediction of the asphaltene gradient based on the previously acquired data offers a new way to optimize wireline logging by comparing the predicted with the actual color gradient in real-time during downhole fluid analysis stations, while the tool is still in the well, to uncover the unknown source of reservoir complexity.