Now a days integrated production modeling is been regarded as a vital part of the oil industry and its very important to manage our reservoir properly as many important decisions regarding the field development depend on it. It is an approach for modeling an entire asset from reservoir to the final delivery point. It facilitates complete integration, and hence full interaction, of different key components of an asset including reservoir, wellbore and surface facilities. It gives the holistic understanding of the entire asset necessary to know how one end of the delivery chain affects the other like separator pressure effect on reservoir pressure, etc. It defines design and operating criteria for a given field, not just for today, but also for the future. In short, it provides the economic optimization of oil and gas recovery.

In this paper, the concept of IPM has been utilized for a newly developed condensate field to come up with the optimum field development strategy using the real field data necessary to evaluate different economic ways of producing the wells. This work presents a methodology which uses compositional modeling, nodal analysis, material balance, reservoir modeling and pressure transient analysis to determine original fluid in place (OFIP), reservoir deliverability and size, number of wells require for developing the field and the optimum producing strategy for the wells. Petroleum Expert's software "Integrated production modeling (IPM) suite 7.5" has been used to carry out this work.

PVT, well test, well logs and production history Data was fed as input to modeling software; PVTP, Prosper and MBAL. A compositional model was prepared in PVTP and was regretted by using laboratory data to minimize error. The results showed very limited production options due to the lower liquid drop-out (less than 12%) and lower volumes of OGIP in the upper bed of the reservoir. Gas recycling option at assumed rate of 30% increases the life of the well upto 5 years and condensate recovery upto 57.5%. After going through all available options, the only option available having economic priorities was to select an optimum wellhead pressure as suggested by the sensitivity analysis to optimize the production was recommended.

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