Use Of Electrical Submersible Pumps Research Articles

Electric Submersible pump (ESP), A Better solution to Heavy Oil Production in Nigeria: Case Study of Enuma 3T in Niger Delta

The use of electric submersible pumps (ESP) in producing conventional heavy oils from hydrocarbon reservoirs is gaining huge attention following the level of success rates recorded in fields where they have been deployed. Howbeit, due to their high failure rates, even at the inception of installation, had made many companies stay clear of its consideration as a means of improving recovery over other artificial oil recovery methods. This study evaluates the impact of the installation of GN 7000 ESP model pump designed to operate at 172 stages at 50 Hz on oil recovery at Enuma 3T well in Niger Delta.

EVALUATION OF THE INTER-REPAIR OPERATION PERIOD OF ELECTRIC SUBMERSIBLE PUMP UNITS

In recent years, in the oil and gas industry of Azerbaijan, the use of electric submersible pumps (SEP) as one of the effective way to increase the level of production of well products. Currently, electric centrifugal pumping units (ECPU) are widely used both on land and in offshore fields. Currently, a total of about 15 % of SOCAR’s oil wells are produced using electric submersible pumping units. ECPU effectiveness is largely determined by both the period of their operation and the frequency of repair and restoration work. It is established that the use of ECPUs contributes to an increase in the service life of equipment and the effectiveness of a mechanized method of oil production. To assess the benefits of the latter, the most important factor is the inter-repair period (Tir) of the equipment. Existing methods for determining the inter-repair period of oilfield equipment are accompanied by large errors, which significantly reduce their reliability. In this regard, the article is tasked with developing a more practical and reliable method for determining the inter-repair period, where the point of change in the nature of the failure rate is adopted as the determining parameter

Оптимизация режимов работы скважин установками электроцентробежных насосов на современном этапе добычи нефти

The history of creation of the Electrical Submersible Pump (ESP) in the United States, which celebrated its 100th anniversary and the beginning of implementation of the ESP in the Soviet Union in the middle of the last century are considered. It is noted that in Russia the rate of oil extraction from the oil fields has been increasing during the past two decades, mainly due to the use of Electrical Submersible Pumps. There are hundreds of standard sizes in the park of submersible rigs for oil production today. ESPs are designed with the outside diameter ranging from 69 to 185 mm, with the capacity of 15–2000 m3/day. In this regard, to optimize “the layer – the well – the pump” system and to improve the efficiency of oil production it is necessary not only to reasonably select the particular size of the pump, but also to skillfully control the operation of wells equipped with ESPs for a long time (for 1.5–2 years). The reason for the continuous monitoring of ESPs operating modes is the presence of a large number of geological and technological factors affecting the formation fluid influx into the well, including the effect of seasonality and weather conditions. The regulation methods of sampling from wells (productivity) by ESP with the wellhead choke and frequency converter are examined. The basic formulas for calculating the choke nozzle diameter, as compared to the use of a frequency converter are shown.

Espirito Santo: The New Deepwater Frontier in Brazil

This article, written by Technology Editor Dennis Denney, contains highlights of paper OTC 19082, "Espirito Santo: The New Deepwater Frontier in Brazil," by Marcio Felix Carvalho Bezerra, SPE, and Nery Vicente Milani De Rossi, SPE, Petrobras, prepared for the 2007 Offshore Technology Conference, Houston, 30 April–3 May. Petrobras has been active in five simultaneous exploration and production frontiers in the Espirito Santo basin, namely gas in shallow water, light and heavy oil in deepwater, and light oil in ultradeep water and onshore. Petrobras has invested in new infrastructure projects including pipelines, processing plants, and a new port to support offshore operations. The company also has participated in research projects in partnership with the Federal University of Espirito Santo. Introduction Petrobras' activities in the state of Espirito Santo, in southeastern Brazil, encompass the Espirito Santo basin (onshore and offshore) and the northern portion of the Campos basin (offshore). Activities began in 1957 with an onshore focus. In 1968, Brazil's first offshore well was drilled in the Espirito Santo basin. In 1978, the Cacao field was the first offshore commercial discovery in the Espirito Santo basin, in a water depth of 19 m. Onshore production began in 1973, reaching maximum production of 25,000 BOPD in 1984, declining to 9,000 BOPD in 1998, when new fields were discovered by use of new technologies (e.g., 3D seismic). In early 2001, the first commercial deepwater discovery was the Jubarte field in the northern Campos basin, followed in 2003 by the discovery of light oil in deep waters in the Espirito Santo basin (Golfinho field). Projects Jubarte. Production began with a 2-month extended well test (EWT). This field produced approximately 20,000 BOPD through the Seillean floating production, storage, and offloading (FPSO) vessel. Phase-1 field development began December 2006 through FPSO P-34 with a production capacity of 60,000 BOPD. Phase 2 is planned for 2010 through FPSO P-57, with a capacity of 180,000 BOPD. Heavy-oil-production technologies include use of long horizontal wells to increase the production, use of electrical submersible pumps (ESPs) installed on the seabed as the main artificial-lift method with gas lift as backup, and the conversion of the FPSO P-34 to process heavy oil. Neighboring the Jubarte field, Cachalote, Baleia Franca, and Baleia Ana fields were discovered in 1500-m water depth. Production is scheduled to begin in 2012. The Baleia Azul field (1300 m water depth), south of Jubarte, may begin operation in 2014. The Caxareu, Pirambu, and Manganga fields were discovered in 2006 and are in the study phase to define the production systems. The Nautilus, Abalone, Ostra, and Argonauta fields are being developed in two phases, with the first phase in 2009, through an FPSO with capacity for 100,000 BOPD. Catua. The Catua field (in water depth of 1800 m), is 50 km southeast of Jubarte and contains 42°API oil in a carbonate reservoir. Discovered in 2005, an EWT is planned for 2008 to define the technical and commercial feasibility.

Champion East: Low-Cost Redevelopment of Shallow, Stacked, and Faulted Heavy-Oil Reservoirs

Summary The Champion East area offshore Brunei Darussalam consists of approximately 50 stacked, shallow, and intensely faulted heavy-oil reservoirs. These reservoirs have been under development since 1975 and have to date produced just 9% of the oil initially in place. Over the period 1998–2003, Brunei Shell Petroleum (BSP) is embarking on a major redevelopment with the aim of converting a further 30 million m3 of oil-in-place volume into commercial reserves. An overview will be given of how new technology is adding value to the total redevelopment, supported by actual application results and learning points. The primary development of Champion East is now nearing completion. The use of existing facilities and ultrashallow, long-reach horizontal wells—with innovative sand exclusion and down-hole intelligence—has achieved a 60% unit cost reduction over previous drilling campaigns in the area. The only way to unlock another 5 to 15% of the oil-in-place volume is to start secondary recovery through water injection, in combination with the use of electric submersible pumps (ESPs).

The Beatrice Field, Block 11/30a, UK North Sea

Abstract The Beatrice Field was discovered in 1976 in Block 1l/30a within the Inner Moray Firth Basin. The reservoir consists of multilayered Lower and Middle Jurassic sediments containing a STOIIP of 480 MMBBL of high wax crude oil. The reservoir sequence comprises 1100 ft of Hettangian (Lower Jurassic) to Callovian (Middle Jurassic) sandstones, siltstones and claystones. The Beatrice Field is co-sourced by a combination of Devonian and Jurassic rocks. The hydrocarbon trap comprises a tilted faultblock, the top of which is truncated by the main field boundary fault. The field has low energy, and the P i of 2897 psi at 6500 ft TVSS, GOR 126 SCF/STBBL and P h of 635 psi, together with the poor aquifer influx, necessitated the development of water injection from the start of production and use of electrical submersible pumps in all wells. Ultimate oil recovery is expected to be 146 MMBBL. The field has been developed with four platforms at three sites in 133 ft waterdepth. The crude is transported 42 miles by peline to the dedicated oil terminal at Nigg on the Cromarty Firth.

Electric-Submersible-Pumping Success in the Beatrice Field, North Sea

Summary When the Beatrice field came into production in Sept. 1981, it was the first North Sea offshore oil field to depend from the outset on artificial lift to maintain production. In view of the low GOR of Beatrice crude, the use of electrical submersible pumps (ESP's) was the only feasible option. Maximization of the operating life of the downhole pump was obviously critical to the economic viability of the project. This paper describes how the ESP performance at Beatrice has been progressively improved through diligent analysis of completion- performance data and failed equipment. The results have led to the optimization of completion design and the development of new and improvement of existing mechanical and electrical components.