The Shushufindi field is the largest oil accumulation (3.8 billion barrels) in the Oriente Basin in Ecuador, and it represents 16% of the total oil production in the country. It was discovered in 1972 and has achieved a current recovery of 1.2 billion barrels of its original oil in place. Its peak oil production was 125,000 BOPD, reached in 1986; since then the production steadily declined. The Ecuadorian government recognized the danger of declining oil revenues, and, in January 2012, the national oil company (EP Petroamazonas) signed a 15-year Specific Integrated Services Contract with Consorcio Shushufindi S.A. (75% Schlumberger, 25% Tecpetrol). During an aggressive optimization campaign performed in the last 10 months, the Consorcio Shushufindi has achieved an incremental recovery of 1.1 million barrels (4,400 BOPD) by rebalancing and optimizing bottomhole flowing pressure over most of the field through increasing the extraction rate. An additional 1.1 million barrels (4,700 BOPD) of production was achieved by performing Electrical Submersible Pump (ESP) upsizings in 24 wells, from a complete portfolio of 34 wells. The Shushufindi revolution demonstrates how an ambitious optimization plan, multidisciplinary integration and collaboration between the operator and the service company can be successful in a mature field despite the associated risks. In addition, this project demonstrates that activities can be performed to increase production at a minimal cost and how to maximize the return on existing assets through the realization of their production potential.
Gas lift optimization and design has traditionally used single-string analysis to perform optimization. This required time consuming exercises and lengthy processes that never achieved the global reach of field constraints management. In a dynamic brown field where field interruptions and process upsets are common, response time is a key performance indicator. These challenges were effectively overcame by introducing a Real Time Production Surveillance and Optimization system capable to perform dual string gas lift optimization field-wide and in real-time. The implementation was the first Real Time Production Surveillance and Optimization system in the country. The system links up real-time operational data historian system and corporate production information management system (PIMS) and is coupled with the Well-Network suite of simulation tools to provide an integrated suite of production surveillance, diagnostic and optimization application modules that increase the efficiency of daily oil and gas operations activities. The goal of this paper is to underscore the advantages and benefits that can be drawn from the utilization of Real Time Production Surveillance and Optimization System during the operational phase of production optimization process.
The Late Neogene Baram Delta province developed on an active margin located offshore Borneo in Malaysia. The field has been in production since 1982, and a total of 64 wells have been drilled from three (3) platforms. This paper discusses the process used to locate remaining oil for infill drilling. This involved a multidisciplinary effort including geology and geophysics, reservoir engineering, drilling / completion, and production technology. The geologic and geophysical (G&G) assessment consisted of updating the static model and constructing mobile oil thickness and structural and bubble maps of all reservoirs. These maps were used in conjunction with original and current fluid contacts and helped to identify and locate remaining oil accumulations. The target portfolio was screened and ranked, and preliminary wellbore paths were built. Four (4) new wells and eight (8) sidetracks combining either shallow or deep targets were passed on to the reservoir engineering team for optimisation from simulation models and first-pass estimation of oil incremental reserves. Reservoir simulation focuses on optimising target intervals as determined through G&G work and drilling design. Well constraints are set to be consistent with operating field production practices and facilities constraints. Completion intervals for the dual-string wells are optimized to minimise water cut and maximise oil rates. All simulation results are rigorously checked against offset well production and observed properties. Once drilling targets are risk-assessed on the basis of structural, fluid contacts, and properties uncertainties, the final well trajectories are designed by the drilling team. This study identified and ranked multiple undrained and appraisal areas. A full infill redevelopment consisting of more than 10 accelerated wells planned through the utilisation of existing facilities was presented and approved by PETRONAS Carigali Sdn. Bhd. (PCSB). The well and target portfolio is focused on three (3) main field development areas: Attic oil in shallow Pliocene reservoirsNew development areas in deeper Miocene levels on the southern blockUntapped deep Miocene reservoirs on the northeastern flank in crestal location The first two (2) sidetracks and three (3) workovers were successfully completed in December 2012, and the current oil production is 40% higher than originally estimated. The successes to date have proved the effectiveness of the concepts that were applied to identify and develop the remaining oil, and the field became East Malaysia's top producer.
TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractIn general, mature oilfields have a good portion of the remaining reserves still trapped due to inefficient drainage, production decline, increase in water cut and sand production and aging of the existing systems. This paper addresses techniques and initiatives to optimize development plans in a mature field. For Bokor Field in particular, there have been identified and implemented opportunities such as Infill drilling and workover optimization, dynamic underbalance perforation (DUP), matrix acidizing and propellant stimulation, water shut-off mechanical (WSOM), sand management, through tubing stand alone screens, deployment of electrical submersible pumps (ESP) and gas lift NOVA valves, real time surveillance (DHG, DTS and LiftWatchers*) and optimization, and microbial EOR.Before the implementation of these techniques, this field had a daily oil production equivalent to 10 MSTBD (after fields decline) and the current production is 26 MSTBD. The two main reason for this increase are:• New technologies were employed in this oil field with dramatic results incorporating new hydrocarbon reserves, via 3D seismic techniques, high resolution stratigraphy and better static and dynamic simulation models. • Multidisciplinary integrated studies to increase field ultimate recovery factors by improvements in drilling, workover, stimulations, facilities and EOR methods.
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