Summary
This paper presents a field-development case study of a low-permeability
turbidite reservoir in Russia. The giant Priobskoye field contains 30ºAPI crude
in laminated sandstones of 0.1 to 20 md at a depth of approximately 2,500 m.
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 waterflooding 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 75,000 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, as shown in Fig. 1. This paper discusses the reservoir-management
optimization of the southern license area, with proved stock-tank oil in place
of more than 6 billion barrels (Amoco Report 1996).
Throughout a period of 20 years, 71 exploration wells were drilled on the
basis of 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
showed higher productivity indices.
The 3D seismic allowed the identification of sandbodies with viable pay
thickness in two pilot areas. The southern area, with one reservoir of 3 to 20
md, and the central area with three stacked reservoirs of 0.1 to 10 md, each
separated by 60-m-thick shale. The reservoirs do not have either free mobile
water or aquifer support.
The production wells usually decline very rapidly without pressure support,
and the recovery factor was estimated to be only 3% if a waterflooding 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 waterflooding patterns from the beginning to avoid
drilling more dry holes. The southern area is waterflooded peripherally, 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 selected 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 [i.e., electrosumergible pumps (ESPs)] 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 pay intervals in each
of the commingled-lenticular reservoirs.
The installation of electronic gauges below the ESPs, together with daily
monitoring, has enabled the operator to evaluate hydraulic fractures by use of
historical pressure and production data without the need for shut-in-pressure
measurements.
A surveillance plan of production, commingled in mutilayer-stimulated
reservoirs, without production downtime through production logging, is present
as well as for injector wells.
Thus, production optimization has focused on hydraulic-fracture jobs with
more-conductive proppant, proper wellbore cleanup before installing ESPs and
wells operating with bottomhole-flowing pressure below the bubblepoint
pressure.
The exploitation approach of this pilot area demonstrated that economic and
sustainable oil production in this kind of complex reservoir is possible. So
far, more than 75,000 BOPD is currently being produced, with an estimated
plateau of 200,000 BOPD in the year 2009, through use of 15 drilling rigs when
the field will be on full development.
© 2008. Society of Petroleum Engineers
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History
- Original manuscript received:
8 June 2006
- Meeting paper published:
31 August 2006
- Revised manuscript received:
29 November 2007
- Manuscript approved:
12 December 2007
- Version of record:
20 May 2008
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