EVALUATION OF IGIP – CGIP RATIO ON DISTRIBUTARY MOUTH BAR SANDSTONE RESERVOIRS IN TUNU FIELD, KUTAI BASIN, EAST KALIMANTAN Case Study in Layer 5f, Geological Area 4 and 5

• Main Author: (NIM: 22015305), DODIONO
• Format: Theses
• Language: Indonesia
• Online Access: https://digilib.itb.ac.id/gdl/view/21817
• Institution: Institut Teknologi Bandung

Tunu Field situated in Mahakam Delta Area, part of Kutai Basin in East Kalimantan. This field is giant gas and condensate field that is found in 1977. After exploration and delineation (appraisal) process, Tunu Field entered development phase and commenced the production in 1990. Until now, its total cumulative gas production has reached more than 9 Tcf, coming from Tunu Main Zone and Tunu Shallow Zone. More than 1000 wells have been drilled in Tunu Field up to now. In general there are 2 (two) reservoir rocks in Tunu Field, distributary channels which are deposited in delta plain area in the west and distributary mouth bars which are part of delta front environment in the east. These two reservoirs have different characteristics in term of dimension, geometry, distribution and quality. <br /> <br /> <br /> Based on latest calculation of Initial Gas in Place (IGIP) and Connected Gas in Place (CGIP) in Tunu Main Zone Field (TMZ), both volumetric have significant <br /> <br /> <br /> difference that induced low CGIP – IGIP ratio. IGIP volumetric is much higher than CGIP. It is because both volumetric has different parameters in its calculation. IGIP is calculated using static data meanwhile CGIP calculation is derived from dynamic data. <br /> <br /> <br /> Eventhough Tunu Field has been produced for 30 years and most of its reservoirs have been significantly depleted, connected volume and gas produced (Gp) are still low compared to its initial volume. The biggest difference between IGIP and CGIP is observed in SU5 (Stratigraphic Unit 5), meanwhile, laterally, Geological Area 4 and 5 are the area with highest IGIP – CGIP discrepancy. In more detail, 5f is one of layers which has biggest difference between IGIP and CGIP, thus this research is focused on this specific layer. The problem that already identified is significant difference between IGIP and CGIP in distributary mouth bar reservoirs, it is probably due to problem in reservoir quality distribution in those bars reservoirs. The aim of the research is to evaluate the factors causing discrepancy between IGIP and CGIP volumetric, its lateral and vertical distribution and to perform evaluation on the parameters used in geomodel and IGIP volumetric calculation which potentially cause too optimistic results e.g. dimension of distributary mouth bar reservoirs and its synchronization with the dynamic data (drainage radius), and the proportion of facies or sandstone type and its reservoir quality. <br /> <br /> <br /> Methodology applied in this research started with facies definition through core to log correlation by reviewing core description and electro-facies analysis from <br /> <br /> <br /> well logs data. Next step is to perform review on petrophysical analysis to define fluid type and type of sandstone with its quality. Sandstone reservoirs in Tunu <br /> <br /> <br /> Field are divided into 3 types, Sand A, B and C based on cut-off from porosity and volume of shale (Vsh). Correlation using well logs is then performed with the <br /> <br /> <br /> support of pressure trend analysis to generate structural maps and to define the dimension and geometry of distributary mouth bars sandstone reservoirs. Prior to perform static reservoir modeling, analysis on the facies proportion and its reservoir quality; and flow probability is done to define parameters that are going <br /> <br /> <br /> to be used in the modeling. It is important to perform the analysis on the reservoir quality because all type of A, B and C sands are contributing to the volumetric <br /> <br /> <br /> calculation, but not all of them have positive contribution to the production, especially type C sand which has less quality. After that, static reservoir modeling is done started with structural modeling, well log upscaling, facies and petrophysical modeling by applying prosity cut-off, and finished with IGIP <br /> <br /> <br /> volumetric recalculation. The results are then to be validated with dynamic data i.e. CGIP. <br /> <br /> <br /> There are some conclusions from the research: dimension of mouth bar sandstone reservoir used in the current modeling fit better with the well correlation results <br /> <br /> <br /> than the average drainage radius from production, this represents its uncertainties e.g. completion type selection and production allocation per layer. <br /> <br /> <br /> From well log data and modeling results, it is confirmed that bar sandstone reservoirs have higher proportion compared to channels, whilst in term of quality, <br /> <br /> <br /> bar sandstone reservoirs show less quality than channels sandstone reservoirs because of higher C sand contents which usually have no or less contribution to the production. After the implementation of porosity cut-off in the IGIP calculation, better CGIP – IGIP ratio is obtained.