Production Optimization of Turbidite Reservoirs in Russia—A Pilot Field Development Case Study

Abstract

This paper presents a field development case study of a low permeability turbidite reservoir in Russia. The giant Priobskoye field contains 30 API crude in laminated sandstones of 0.1 to 20 md at a depth of around 2500 meters. The complex geology, lack of reservoir information and lack of technology availability caused a 20-year gap between discovery and development. The initial pilot development was halted after poor drilling success, thus the operator invested in 3D seismic acquisition and an integrated, multidisciplinary reservoir modeling and simulation effort. The subsequent development was based on oriented water flooding patterns and massive hydraulic fracturing, together with an artificial lift system equipped with permanent pressure and rate monitoring for evaluation and real time production enhancement. The optimization of operational practices and introduction of fit for purpose technologies enabled a production increase from an intermittent hundreds of BOPD to more than 75000 BOPD in a period of 3.5 years. The exploitation strategy of this pilot area demonstrated commercially sustainable production from the reservoir and will form the basis for full field development. Introduction The Priobskoye field, located in the Central part of West Siberia, was discovered in 1982. The field was divided into two license areas: Northern and Southern areas as shown on figure 1. This paper will discuss the reservoir management optimization of the Southern license area (SLA) with proved STOIP over 6 Billion barrels1. Throughout a period of twenty years, 71 exploration wells were drilled based on 2D seismic and log correlation of lenticular sandstones. The exploitation of the field had been postponed because most of the wells showed poor productivity index. Also, 13 of the wells were dry holes. In 2002 the operator decided to acquire 900 sq km of 3D survey in the area where the wells had showed higher productivity indices. The 3D seismic allowed the identification of sand bodies with viable pay thickness in two pilot areas. The southern area with one reservoir of 3 to 20 md and the central area with 3 stacked reservoirs of 0.1 to 10 md, each one separated by shale, 60 meter thick. The reservoirs do not have either free mobile water or aquifer support. The production wells usually declined very rapidly without pressure support and recovery factor was estimated to be only 3% if a water flooding program was not implemented. Also, the knowledge of maximum in-situ stress orientation allowed creating a geomechanical model for proper well placement. Consequently, a multidisciplinary geological and reservoir modeling team helped to define the optimum water flooding patterns from the beginning and to avoid drilling more dry holes. The southern area is being waterflooded peripherilly while the central area is line drive-oriented to avoid premature watering out of production wells. A commingled production completion of the three reservoirs was decided in the central area, because it was uneconomic to produce only one reservoir by itself. The initial pilot development was based on massive hydraulic fracturing accompanied with a lift system (ESP's) to take advantage of the enhanced productivity. The main purpose of the hydraulic fracturing was not only to increase the productivity index of the wells but also to provide connectivity between the borehole and all the pay intervals in each of the commingled lenticular reservoirs. The installation of electronic gauges below the ESP pumps, together with daily monitoring has enabled the operator to evaluate hydraulic fractures by using historical pressure and production data without the need for shut-in pressure measurements. The surveillance plan of production commingled in muti-layer stimulated reservoirs without production downtime via production logging is presented as well as for injector wells. Thus, production optimization has been focused on hydraulic fracture jobs with more conductive proppant, proper wellbore cleanup before installing ESP's and wells operating with bottom hole flowing pressure below the bubble point pressure.