Abstract The South Tapti gas field, located in the Arabian Sea off the western coast of India, has been on production for the last three years. Drill Stem Tests (DST) conducted in five zones in the first appraisal well showed high sand production in all the tests at drawdowns as low as 20 psi. Due to the unconsolidated nature of the reservoir sand, it was decided to gravel pack all future wells. Initially, the High Rate Water Pack (HRWP) technique was used on 13 completions including some stack and selective completions.
Due to a change in the drilling fluid to an oil based mud (OBM) system and the higher damage associated with the it, it was later decided to switch the gravel packing technique to ‘Frac and Pack’. This involved creation of a small frac to bypass the near wellbore damage using a gel-based fluid, followed by gravel placement using the HRWP. The Frac & Pack technique was tried on 10 completions. Extensive production and pressure data collected on the above completions show that the ‘Frac & Pack’ technique has led to a decrease in the mechanical skin by almost 70 %.
More importantly, it has also been responsible for decreasing the Rate Dependent Skin Coefficient, D, by 50 %, which has a greater impact on the well productivity since these wells are produced at average rates of 25 MMSCFD. This paper describes the gravel packing techniques used in the South Tapti gas field, their evolution and the results achieved. Inroduction The South Tapti field, located off the Western coast of India, is represented by a series of alternating sand and shale sequences.
The upper reservoir intervals are dominated by tidal-bar and channel sands deposited in a deltaic environment while the lower sands represent incised valley deposits consisting largely of alluvial/fluvial channels, tidal bars and tidal creeks. The exploratory wells drilled in the field indicated strong sand production tendencies due to the unconsolidated nature of the reservoir rock. This was corroborated by extensive testing of the first development well when all the five zones tested produced sand even under extremely low pressure drawdown conditions.
The completion policy for the field focused on preventing sand ingress while minimizing the near well-bore damage inherent in any sand control application. The early development wells were gravel packed using the high rate water pack (HRWP) technique. These initial completions were highly successful in preventing sand production but also induced significant damage in the process. The problem was accentuated when the drilling mud system was changed to an oil base system in an attempt to offset recurrent drilling problems arising out of unconsolidated sandstone and presence of reactive clays.
This called for a change in completion philosophy in order to ensure that the wells retain high productivity with effective sand control. Geologic and Reservoir Characterization The South Tapti field is localized by a broad SW-NE trending, doubly plunging anticline. The field has up to 13 different Oligo-Miocene gas bearing sands, separated by shales. The reservoir sands were deposited in both incised valley and deltaic settings. Reservoir sands within incised valleys consist of alluvial/fluvial channels, tide-influenced channels and tidal bars.
The channel sands typically are the cleaner sands with excellent porosity & permeability and up to 20 m thick, whereas the tide-influenced channels and tidal bars are shalier, with more modest porosity and permeability. CLAY MINERALS 1. Abstract: Tapti Basin in Surat Depression, Bombay Offshore is characterized by entirely siliciclastic succession. The cores and cutting samples, and wireline logs provide important information about the stratigraphy, basin fill, mineralogy, source and reservoir rock characteristics.
Well under study is located in South Tapti sub-basin and contains gas-bearing sandstone within Mahim Formation of Late Oligocene age. The cuttings and cores have been megascopically examined and with the aid of electrical log data, the litholog of the well is prepared. The study involves XRD and major element analysis of selected samples. The XRD and digital log data from Natural Gamma Sepctrometry (NGS) log indicate that montmorillonite is the major clay mineral present in the upper part of the succession, whereas kaolinite present in the lower part (1868 m MD to 2427 m MD).
Kaolinite is apparently formed by early stages of burial diagenesis, whereas montmorillonite is a weathering product of the Deccan Basalt. Interpretative lithology from the well log response shows that reservoir sandstones have developed within the depth interval of 1865m TVD to 1945 m TVD within dominantly shale lithology. Reservoir sandstones are semiconsolidated, medium to coarse grained and moderately well sorted. Quartz is the dominant detrital component in all the sandstones.
Pay sands are quartz arenite whereas non-pay sands are quartz wacke with varying amount of clay matrix. Kaolinite in the reservoir section reduces the permeability of quartz wacke, but enhancing porosity in microlevel. Carbonate, siderite and iron oxide are main cementing material. Major element data showing that clastic sediments were delivered to the basin possibly by the Proto Tapti river but they may be having dual source of origin. The discriminant functions of Meyer and Nederlof, 1984 has indicated that the studied formations do not have source rock potential.
Key words: Tapti Basin, Bombay Offshore, hydrocarbons, provenance and clay minerals. quartz wacke, but enhancing porosity in microlevel. Carbonate, siderite and iron oxide are main cementing material. Major element data showing that clastic sediments were delivered to the basin possibly by the Proto Tapti river but they may be having dual source of origin. The discriminant functions of Meyer and Nederlof, 1984 has indicated that the studied formations do not have source rock potential.