Авторское право 2008 г., Общество инженеров-нефтяников Этот доклад был приготавливан предьявления в 2008 Российской нефтьегазовой технической конференции и выставке состоится в Москве 28-30 октабря 2008.Данный доклад был выбран для проведения презентации Программным комитетом SPE по результатам экспертизы информации, содержащейся в представленном авторами резюме. Экспертиза содержания доклада Обществом инженеров-нефтяников не выполнялась, и доклад подлежит внесению исправлений и корректировок авторами. Материал в том виде, в котором он представлен, не обязательно отражает точку зрения Общества инженеров-нефтяников, его должностных лиц или участников. Доклады, представленные на конференциях SPE, подлежат экспертизе со стороны Редакционных Комитетов Общества инженеров-нефтяников. Электронное копирование, распространение или хранение любой части данного доклада в коммерческих целях без предварительного письменного согласия Общества инженеров-нефтяников запрещается. Разрешение на воспроизведение в печатном виде распространяется только на резюме длиной не более 300 слов; при этом копировать иллюстрации не разрешается. Резюме должно содержать явно выраженную ссылку на то, где и кем был представлен данный доклад. Write Librarian, SPE, P.O.Box 833836, Richardson, TX 75083-3836 U.S.A., факс 01-972-952-9435.

A major exploration and production company operated Block 15 and unified fields Eden-Yuturi and Limoncocha from 1986 to May 2006, when the contract passed back to the Ecuadorian Government. In 2004 a decision was made to implement an ESP Real Time Monitoring and Diagnosis system in order to optimize production and improve ESP operations. The system includes automation hardware equipment and a server-client software package. The purpose of this paper is to give details about the benefits of remote monitoring and control of Electrical Submersible Pumps, and the real results achieved from using the ESP monitoring and diagnosis system to monitor, analyze, and remotely control ESP performance at Block 15. In this paper, we will highlight ways in which the ESP diagnosis system has enabled material improvements in operational efficiency at Block 15.

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As companies working in the oil and gas industry move into the Digital Energy age, they often have to deal with legacy SCADA platforms that fail to meet the challenges of supporting their growing enterprise. Intelligent asset management across a company's entire network of pipelines, plants, and producing fields requires the acquisition, management, and manipulation of large volumes of data. Without the proper enterprise strategy in place, a company often finds itself with fragmented data and applications all across the enterprise and unusable or unmanageable IT systems. These fragmented solutions often become a liability when trying to manage an asset's technology, equipment, and people.A short list of the Technical and People Challenges include: • Addressing SCADA systems that historically were managed by I&E field personnel • Multiple SCADA vendors, solutions, and versions deployed • Challenges associated with the IT responsibilities being outsourced to multiple integrators • A multiple integrator and system approach, creating installations that are unique and independent from each other • Addressing a network infrastructure that allows for enterprise visibility • Historical data warehousing that was never in scope with future needs This paper discusses an enterprise approach to SCADA that supports distributed assets across multiple vertical sectors (plants, pipelines, producing facilities). The approach has been implemented in several CO2 enhanced oil recovery (EOR) projects by Denbury Resources, as it solves the requirements for support of the process and business network, data replication, system failover, redundant control centers, and data historization and management across the enterprise. Denbury is deploying the enterprise SCADA system in a growing number of its CO2 EOR assets, which includes both projects that are being converted and new assets being added through the acquisition of properties.

A simple electronic control method for automatically determining the "on-time" parameter for intermittent gas lifted wells using existing continuous gas lift valves is presented. Lift gas consumption and production during intermittent operation is compared to previous continuous gas lift results of the same wells in an unconventional reservoir. Performance during abnormal field conditions is analyzed. Interpretation of pressure/flow curves is explained. Algorithms in electronic controllers normally used for plunger lift optimization are adapted to intermittent gas lift. Several pressure and flow phenomenon indicate the stage of the intermittent gas lift cycle. The most important indicator is a sudden increase in tubing pressure and gas production rate which signifies the arrival of fluid at the surface of the well. A setpoint is used to determine that the fluid slug has arrived and the gas injection is then brought to a halt until a timer or other parameter determines the beginning of the next injection cycle. Nearly all wells which were tested with the new control algorithm showed a large drop in consumption of lift gas, which was the only target of the test. The wells which showed the greatest lift efficiency improvements produced on average less than 150 barrels of total fluid per day. Many wells may have been producing less fluid under continuous gas lift due to higher average bottomhole pressure under continuous injection conditions. Nearly all wells maintained or increased production after the change. The use of an automatic on-time adjustment maintained production under scenarios where strict timer-based systems would have failed to produce fluid. The amount of time needed to restart a well after an automatic shut-in was reduced by closing the gas lift injection valve when a flow obstruction was indicated by rising tubing pressure and automatically restarting the well when conditions improved. This method is a simplified control strategy which can be implemented and maintained with little user intervention. Practicing engineers responsible for optimizing large groups of wells may find value in this novel strategy. The shale operator received a ROI of 7 days using this new approach.