The five large oil fields found in the Russian Republic of Tatarstan have been producing from the Devonian sandstone reservoirs for more than fifty years. Currently all of them have entered the maturity stage. In all five fields waterflooding methods have been applied since the very start of production. And though the principal development approaches and strategy do not differ, development rate, volumes of fluid produced, actual and design oil recovery factor (ORF) do differ. The largest of the five fields, Romashkinskoye, has been developed in independent areas divided by injection wells' rows. There are 21 such areas. Comparative analysis of these areas' performance is of specific interest.

To make a generalized estimate of production performance of the five fields, we have ranked them by a number of geologic parameters. The same ranking has been performed for all areas of the Romashkinskoye oilfield. For the purpose of analysis these areas have been further divided into seven groups by a common integral geologic parameter.

The investigation method involves a correlation analysis of the fluid production and oil recovery profiles at different stages of development of both fields and areas; as well as evaluation of the present-day status of development, in that number with account for the tendency towards operating assets' change.

It has been demonstrated that the oil recovery factor and its behavior at different development stages depend to a large extent on reservoir geology. Besides, there is a close correlation between fluid and oil production rates. In mature fields very important factors are status of assets and producing wells' density. Fields and areas have been identified which call for immediate rejuvenation operations.


The relationship between recovery factor and fluid volumes and production rates has been the subject of much investigation. Not infrequently this issue is discussed in connection with forced fluid withdrawal. Oil recovery mechanisms with different fluid production rates may be numerous in number. This complicates construction of adequate mathematical models. Neither does physical simulation on cores reflect all factors which influence the process of filtration at different production rates. This makes many of the researches turn to the analysis of actual performance history at different drive behavior. The results presented may be totally different: from recognition of dependence between oil recovery and development rates to its complete rejection. It appears that both points of view have the right to exist, and the deciding factors are geologic setting, reservoir properties, and fluids' characteristics. This assumption allows the authors to skip whatever review of published papers and present our own results. Novelty element in our study is ranking of being analyzed oil fields and areas according to a number of geological factors [1, 2], which include net pay thickness (m), porosity (%), permeability (µm2), oil saturation (%), net-to-gross ratio (NGR) (decimal fraction), NGR variation, number of pay intervals and its variation, reserves by lithological groups (%), distribution of reserves by formations.

All production parameters have been analyzed in the dimensionless form, as a ratio to original oil-in place (OOIP) in a development target.

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