FACIES ANALYSIS AND RESERVOIR DISTRIBUTION OF TELISA FORMATION IN BINTANG FIELD, CENTRAL SUMATERA BASIN

• Main Author: Nukefi, Alvey
• Format: Theses
• Language: Indonesia
• Subjects: Geologi, hidrologi & meteorologi
• Online Access: https://digilib.itb.ac.id/gdl/view/80066
• Institution: Institut Teknologi Bandung

The Central Sumatra Basin has proven to be a hydrocarbon-producing basin and is one of the most productive basins in Indonesia. The largest hydrocarbon accumulation in this basin is in the Sihapas Group which consists of several rock formations, namely the Menggala Formation, Bangko Formation, Bekasap Formation, Duri Formation and Telisa Formation. However, unlike other formations, the Telisa Formation is currently less developed and is better known as a cap rock. In Bintang Field, reservoir heterogeneity such as porosity and permeability in the Telisa Formation is considered as one of the factors that limit the development and production of hydrocarbons. This study was conducted to identify the type of rock facies and their distribution in 3 reservoirs in the Telisa Formation such as T15A, T15B and T15C through a sequence stratigraphic approach so that it is expected to provide information and correlation with the reservoir heterogeneity. The data used in this study were wireline logs from 61 wells, 3D seismic data, biostratigraphic reports from 4 wells, core rock reports from 3 wells and porosity and permeability data from 61 wells. The lithofacies and electrofacies analysis that has been performed show that the Telisa Formation reservoir has 4 (four) types of facies associations: Transgressive Lag Deposit, Tidal Bar Deposit, Immature Tidal Bar Deposit and Shallow Marine Deposit. The Transgressive Lag Deposit is composed of Glauconitic Sandstone and Floating Pebbles Sandstone, Tidal Bar Deposit is composed of Wavy Flaser Sandstone, Tidal bar Immature deposit is composed of alternating fine-very fine Sandstone with Siltstone and Shallow Marine is composed of Laminated Siltstone and Massive Siltstone. By sequence stratigraphy, the reservoirs of the Telisa Formation, namely T15A, T15B and T15B, are a part of one set parasequence that is deposited progradationally and is limited by the Maximum Flooding Surface (MFS). Transgressive lag deposits were found to be quite abundant in this Bintang Field, accompanied by an abundance of glauconite mineral and ravinement surface at the bottom of the layer which then used as transgressive surface. The sandstone reservoir of the Telisa Formation is concluded to be deposited in a Mixed-Dominated Estuarine environment based on information of paleobatymetric deepening which indicates a transgressive phase, a prograding depositional stacking patterns as well as abundance of heterolithic sedimentary structures such as wavy, flaser and ripple indicating a depositional environment with strong tidal influence. Estuarine Gironde in France is used as an analogue in the depositional model. The distribution map for the reservoir facies association of the Telisa Formation shows the dominance of the Shallow Marine Deposit in the T15A reservoir where Tidal Bar and Immature Tidal Bar deposits are only found in limited area. Tidal Bar and Tidal Bar Immature deposits begin to develop in reservoir T15B and reach their peak in reservoir T15C. Tidal Bar and Tidal Bar Immature deposits in Bintang Field generally have a direction of North – South and Southwest – Northeast. Transgressive Lag deposits are found in several places on three reservoirs and located parallel to Tidal Bar/Tidal Bar Immature deposits. Validation of facies association maps with reservoir property data such as porosity and permeability generally showing a good correlation. In reservoirs T15A and T15C, facies associations of Tidal Bar and Immature Tidal Bar Deposits have high values and significant differences in porosity and permeability. Reservoir of T15B shows that the difference in porosity and permeability values is not large enough between the facies associations of Tidal Bar, Tidal Bar Immature and Shallow Marine Deposit. The results of this validation indicate that the heterogeneity of reservoir properties (porosity and permeability) is generally caused by facies variation. Some anomalies / deviations are thought to be caused by diagenesis or tight sand which causes the porosity & permeability values to increase / decrease.