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.

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TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractThe 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.

The Panna field is a heterogeneous limestone reservoir consisting of a thin oil column overlain by a gas cap and underlain by a water column. The reservoir is coning dominated and the wells show a marked increase in Gas Oil Ratio (GOR) and water cut very early in the production history. Horizontal wells were drilled to minimize drawdown, and hence coning, and maximize recovery. The initial horizontals had openhole completions and displayed a peculiar inflow performance curve that was concave upwards and almost flat at the higher rates. This was thought to be caused by the formation of water sumps at low rates, due to the undulating profile of the drainhole & the low fluid velocities, which resulted in a non-uniform flow contribution along the horizontal. Subsequent wells were completed with a centralized, selectively perforated tubing (tailpipe) installed in the drainhole and it was thought that this would result in a uniform flow contribution along the entire horizontal section and correct the inflow performance curve shape. Analysis of pressure data from the tailpipe wells showed that the tailpipe caused progressively higher drawdown at high rates. However, the flow distribution along the drainhole could not be determined from pressure data alone. A production logging campaign utilizing tractor as the conveyance system had to be aborted due to a) limited coverage of the horizontal section by the tractor and b) operational problems resulting in fishing of the tractor in one of the wells. This campaign was expected to provide an insight into the flow process in the two completions and determine the most optimum one. This case study presents the performance of the various horizontal completions in existence in the field and integrates production and bottom-hole pressure data to explain them. Introduction Panna field is located in the Bombay Basin in Western offshore India 50 km east of the giant Bombay High Field and 95 km Northwest of the city of Mumbai (Bombay). It has initial oil in place of over 1 billion barrels. The field presently has 63 wells of which 19 are vertical wells and 44 horizontal. The horizontal wells have been completed in three different ways: openhole, stinger completions and perforated tailpipe completions. A brief description of the different completion schemes and efforts made to evaluate them are presented in the paper. Modeling studies indicate preference towards tail-pipe completions, but measured production and pressure data indicates that the barefoot completions are advantageous when producing at high liquid rates. Reservoir Geology The principal hydrocarbon bearing formations in Panna Field are the Middle Eocene Bassein B Upper and the Early Eocene Bassein A limestones. An unconformity representing approximately 4 million years of Upper Eocene time separates the Bassein A and B zones. These are ramp setting, tropical limestone deposited in marginal marine to inner nerritic depths in a low to moderate energy environment. A structural cross-section of the Panna field is shown in Figure 1.