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Abstract Production from Artificially lifted (ESP) well depends on the performance of ESP and reservoir inflow. Realtime monitoring of ESP performance and reservoir productivity is essential for production optimization and this in turn will help in improving the ESP run life. Realtime Workflow was developed to track the ESP performance and well productivity using Realtime ESP sensor data. This workflow was automated by using real time data server and results were made available through Desk top application. Realtime ESP performance information was used in regular well reviews to identify the problems with ESP performance, to investigate the opportunity for increasing the production. Further ESP real time data combined with well model analysis was used in addressing well problems. This paper describes about the workflow design, automation and real field case implementation of optimization decisions. Ultimately, this workflow helped in extending the ESP run life and created a well performance monitoring system that eliminated the manual maintenance of the data. In Future, this workflow will be part of full field Digital oil field implementation.
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (21 more...)
Abstract The time taken to safely optimise a reservoir produced by artificial lift can be measured in weeks or months. Typically the well by well process is as follows: Well testing Amalgamation of the well test data with down hole gauge and ESP controller data Analysis of the data to find the existing operation conditions Analysis of the ESP pump curve operating point and optimisation limitations Sensitivity studies in software to assess the optimum frequency and WHP Notification for the field operations to action the changes Further well tests to verify the new production data. Analysis of the data to ensure the ESP and well are running optimally and safely at the new set points New technology enables this process to be performed in real time across the entire reservoir or field, significantly shortening the time to increased production and enabling real time reservoir management. Each artificially lifted well in the reservoir was equipped with an intelligent data processing device programmed with a real time model of the well. The processors were linked to a central access point where the operation of field could be remotely viewed in real time. Each well’s processor was provided with a target bottom hole flowing pressure to enable the optimum production of the reservoir. The real time system automatically compared the desired target drawdown values with the capability of the pumping system installed in each well, and automatically suggested the optimum operating frequency and well head pressure to achieve the target. Where the lift system was not capable of producing to the target bottom hole pressure, a larger pump was automatically recommended. As production conditions change the system adapted its recommended operating points to compensate and maintain target production. This paper discusses three case studies where real time optimisation and diagnosis lead to improved production from the reservoir.
- Asia > Middle East > Israel > Mediterranean Sea (0.24)
- Asia > Middle East > Kuwait (0.15)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Drillstem/well testing (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring (1.00)
- Production and Well Operations > Artificial Lift Systems (1.00)
- Data Science & Engineering Analytics > Information Management and Systems (1.00)
Abstract At Kuwait Oil Company (KOC) most of the ESP wells are running with downhole sensors to enhance the daily monitoring routine and for having a better knowledge of the pumps performances. However, one of the most important parameter of these ESP Wells is only known after a time period within 3-6 months: The Flow Rate. Production Tests are obtained using Multiphase Flow Testing Units which usually last between 4 and 6 hours that are also utilized to conduct some sensitivities such as choke size and motor speed changes. At Well Surveillance Group, a tailored fit model was developed from which the ESP flow rate can be estimated based on the downhole sensor data and basic fluid properties with an overall deviation below 2% (when they are compared to the results obtained from the Testing Unit). In this sense, flow rate monitoring can be performed at any time and flow testing time and associated cost can be reduced among other benefits. The method requires knowing the ESP model and total number of stages installed in the well, and then using the corresponding performance curve of the ESP model usually provided by the manufacturer, the data is processed and the calculation performed. This work aims to show how this model works, advantages, limitations, implementation status and future improvements.
- North America > United States (1.00)
- Asia > Middle East > Kuwait (0.71)
An Iterative Solution to Compute Critical Velocity and Rate Required to Unload Condensate-Rich Saudi Arabian Gas Fields and Maintain Field Potential and Optimal Production
Al-Jamaan, Hamza (Saudi Aramco) | Zillur, Rahim (Saudi Aramco) | Bandar, Al-Malki (Saudi Aramco) | Adnan, Al-Kanan (Saudi Aramco)
Abstract Saudi Arabian non associate gas reservoirs produce various amounts of condensate depending upon field and reservoir. In most cases, these wells are hydraulically fractured and at the initial stage after such stimulation treatment, each well needs to unload high quantity of the pumped fluid to ensure full potential. If the liquid starts accumulating in the wellbore during production, the well productivity will gradually decrease and eventually may stop producing. If the gas flow velocity in the production string is high enough, the gas will continue flowing and will carry the liquid droplets up the wellbore to the surface. The minimum velocity and critical gas rate (Qcrit) are therefore the determining factors while producing a well or several wells from a condensate-rich field so as to ensure the stable field production rate and maintain production plateau. An analytical model has been developed to iteratively compute the critical velocity (Vcrit) and Qcrit, for given flowing wellhead pressure (FWHP), tubing diameter, and many other reservoir and completion properties. If the FWHP is set and a certain production rate is expected of a well, the program automatically computes the pressure drop due to friction, dynamic hydrostatic head, and the bottomhole pressure. Simultaneously, both Vcrit and Qcrit to unload the fluids are calculated. If the Qcrit is above the expected production rate, a different wellbore completion is automatically selected and computation is continued until Qcrit is lower than the expected rate of the well. If this is not possible, the program will display appropriate message. Several wells from a condensate gas reservoir are analyzed from a field that has to maintain certain production potential for a given number of years. The analyses show that the wells that are producing without intervention are those that are confirmed by this model to be flowing above the Qcrit. For wells that were intermittently producing and ultimately could not sustain production were producing at rates below the critical values. Using this iterative model, those rates are automatically adjusted or new completion string is suggested to bring them back into production.
- Asia > Middle East (0.94)
- North America > Canada > Alberta > Stettler County No. 6 (0.24)
- North America > Canada > Alberta > Starland County (0.24)
- (2 more...)
Abstract CO2/CH4 exchange in a sandstone-hosted methane hydratereservoir was executed in the field, following several years of laboratoryexperimentation. Reservoir simulation and laboratory data informedfieldtrial design, including use of a cell-to-cell model that included correctliquid/vapor/hydrate phase behavior of methane, carbon dioxide, nitrogen, andwater. Most concepts for producing methane from hydrate deposits rely ondepressurization, heating, or chemical melting. These techniques resultin dissociation of hydrate into its water and gas constituents. Effectiveexchange of CO2 for CH4 in the crystalline hydratelattice, without dissociation, was long deemed an improbable recovery strategybecause experimental results on bulk hydrate samples indicated very slowreaction kinetics. Recent laboratory tests documented enhanced exchangekinetics and efficiency, attributed to the increased surface area present inporous media. A series of laboratory tests ranging from simple gas-richsystems to more complex gas-deficient / water-rich systems guided the design ofa field test program. Ignik Sikumi #1 was drilled in 2011 on the AlaskaNorth Slope, designed specifically for testing CO2/CH4exchange in hydrate-bearing sandstones. Ignik Sikumi #1 was drilled vertically with chilled oil-based mud to a depthof 2600ft. Four hydrate-bearing sandstones were encountered, andpetrophysical evaluation indicated the Sagavanirktok " C Sand" hosted thehighest hydrate saturations. These sandstones occur in the subsurface atreservoir conditions similar to temperatures and pressure conditions of labtests. Reservoir modeling with conventional simulators and in-housecell-to-cell models guided both equipment design and test parameters. Anticipated low injection rates and cryogenic injectant required the design ofspecialized pumping equipment. Operations at Ignik Sikumi #1 re-commencedin December 2011. Following perforation, over 200,000 scf of mixedCO2/N2 gas was injected. A short unassisted flowperiod was followed by extended production testing via jet pumping. Results from the production test will be shown. CO2/CH4 exchange is a novel approach to recovermethane from sandstone-hosted hydrates. Field trial has validatedlaboratory results and reservoir simulations, and has proven thatCO2 can be injected into naturally occurring sandstone-hostedhydrates. Subsequent flowback/drawdown testing produced injectants(nitrogen, carbon dioxide, and tracer gases) methane, water, and very finesand.
- North America > United States > Alaska > North Slope Borough (0.29)
- Africa > Nigeria > Gulf of Guinea > Niger Delta (0.24)
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > North America Government > United States Government (0.48)
Abstract This paper describes the selection, design, successful application and performance monitoring of Electrical Submersible Pumps (ESP) in the giant Mangala oil field and Thumbli water field situated in the Barmer basin in Rajasthan, India. Mangala oil field contains in excess of 1 billion barrels of STOIIP (Stock Tank Oil Initially in Place) in high-quality fluvial reservoirs. The field was brought on production in August 2009 and is currently producing at the plateau production rate of 150,000 bopd of which approximately more than one- third of the oil production is from the ESP oil wells. To support the water requirement of Mangala and other satellite oil fields, Thumbli source water field was developed with 5 water production wells with up to 4 wells operating at a time. Each of these water wells is installed with 60,000 bwpd capacity pumps and the field is currently producing up to 225,000 bwpd to meet the water requirements of Mangala and other satellite fields. The Mangala oil field is a multilayer, multi-Darcy reservoir, has waxy viscous crude with in-situ oil viscosity up to 22 cp and wax content in the range of 18 to 26%. The field was developed using hot water flood for pressure maintenance. Significant production challenges included unfavorable mobility ratio with early water cut and hence the early requirement of artificial lift to maintain the plateau production rate. The field has 12 horizontal producers and 92 deviated producers. ESP was selected as the artificial lift method for the high rate horizontal producers while hot water jet pumping was selected as the artificial lift method for low rate deviated oil wells. Each horizontal well is capable of producing up to 15,000 blpd and high rate ESPs were designed and installed to deliver the production requirement. Currently 8 of the 12 horizontal producers are on ESP lift and the remaining four wells are planned for ESP installation in the near future. Apart from two early ESP failures during installation, ESPs have had a good run life; the paper also describes lessons learnt from the infant mortalities. The Thumbli water field, located ~20 km southeast of Mangala field has been developed to meet the water requirement of Mangala and other satellite fields. Thumbli water aquifer is a shallow water field which contains water of ~ 5000 ppm salinity with dissolved CO2, oxygen, chlorides and sulphate reducing bacteria (SRB). 5 high capacity water wells were drilled in Thumbli field to meet the huge water demand from Mangala for water injection in Mangala and satellite field injector wells, hot water circulation in oil production wells and associated water requirement for boilers etc. 1000 HP water well ESPs were designed to produce up to 60,000 bwpd from each well with installed water production capacity of up to 300,000 bwpd from Thumbli field. A state of the art ESP control and monitoring architecture including ESP tornado plotting was developed and successfully implemented in the ICSS to remotely operate, monitor and optimize ESP well performance from the central control room within Mangala field and from the company headquarter located in Gurgaon.
- Geology > Sedimentary Geology > Depositional Environment (0.34)
- Geology > Mineral > Sulfate (0.34)
- Oceania > Australia > Western Australia > Indian Ocean > Perth Basin > Abrolhos Basin > Block WA-325-P > Cliff Head Field (0.99)
- Asia > India > Rajasthan > Rajasthan Basin > Barmer Basin > Rajasthan Block > Mangala Field > Fatehgarh Formation (0.95)
- Asia > India > Rajasthan > Rajasthan Basin > Barmer Basin > Rajasthan Block > Mangala Field > Barmer Hill Formation (0.95)
- (9 more...)
Abstract This paper describes the selection, field application and performance monitoring of jet pumps in the giant Mangala field situated in the Barmer basin in Rajasthan, India. The field contains more than a billion barrel of STOIIP (Stock Tank Oil Initially in Place) in high-quality reservoirs. The field was brought on production in August 2009 and is currently producing at a plateau of 150,000 bopd. Mangala field is characterized by multi-Darcy rocks with mix to oil wet characteristics. The oil is waxy and viscous, with wax appearance temperatures close to reservoir temperature. Jet pump has been selected as the preferred artificial lift method for the deviated wells. The base development plan included hot water flooding; this makes water heated up to 85 °C available at the well pads as power fluid for jet pumping. In order to prevent exposure of carbon steel production casing to corrosive reservoir fluid, the jet pumping process involves pumping the power fluid down the annulus and taking returns through the tubing. The results have indicated that the jet pumps are giving required drawdown, thereby restoring the liquid productivity of the wells. In addition to restoring well production, jet pumping has also been used as an effective and fast method for cleanup of deviated wells completed with sand screens. The real time monitoring of the jet pump parameters, using Digital Oil Field (DOF), has immensely helped in efficient monitoring the pump performance and reducing the response time in case of problems. Jet pump application has helped in restoring the deliverability of wells at high water cut for such a viscous crude. Further analysis of the pump behavior will provide insight for efficiently operating these pumps which is critical for maximizing recovery from the field at higher water cuts.
- Asia > India > Rajasthan > Rajasthan Basin > Barmer Basin > Rajasthan Block > Mangala Field > Fatehgarh Formation (0.99)
- Asia > India > Rajasthan > Rajasthan Basin > Barmer Basin > Rajasthan Block > Mangala Field > Barmer Hill Formation (0.99)
- Asia > India > Rajasthan > Rajasthan Basin > Barmer Basin > Fatehgarh Formation (0.99)
- (2 more...)
- Information Technology > Architecture > Real Time Systems (0.54)
- Information Technology > System Monitoring (0.54)
Abstract Many researches had been carried out on the water jet pumps during the last few decades, and discussed the effect of changing the pump geometric parameters on its performance. Some other researches investigated pump performance with Two-phase (liquid-gas) and (liquid-solid) flow. In spite of the several researches, which investigated the case of liquid-liquid flow (almost as water-water), neither of them did have examined the case in which the secondary flow liquid differs from the power flow liquid in density and viscosity, which is the main objective of this paper. The subject is treated experimentally on a special test rig, with the primary fluid jet water and the secondary fluid of different types of oils. Performance of the jet pump and static wall pressure inside the mixing chamber, were measured as a function of the mixture Reynolds number. A one-dimensional analysis is also carried out, taking into account the difference of the viscosity and density of the two liquids (each primary and secondary fluids). One-Dimensional Equations for the Jet Pump Performance The one-dimensional flow assumptions are:- 1- Streams are one-dimensional at the entrance and exit of the mixing chamber. 2- Mixing is completed in the mixing chamber area. 3- Spacing between the nozzle exit and inlet of mixing chamber is zero, which is attainable due to the small nozzle diameter, relative to the large diameter of the mixing chamber. Momentum and continuity equations [3] were applied to different sections of the jet pump, namely the suction, inlet and outlet of the mixing chamber and the outlet of the diffuser. From this, the relationships between M, N & h and the performance of the jet pump were determined.
Abstract A sour carbonate reservoir has been identified for water flooding to improve hydrocarbon recovery. The field is situated in the South of Oman and was discovered by PDO in 2005. Production began in 2007 and contains crude oil with 30° API oil gravity and solution GOR of 80 Sm/m, as well as, sour fluid contaminants of 5 mol% H2S and 3 mol% CO2. Reservoir water fluid samples confirm salinity is more than 220,000 mg/L chloride ions. While the reservoir is over-pressured at more than 600 bara with a bubble-point pressure of 140 bara, reservoir pressure continues to decline during the initial depletion phase of the field development. Although water flooding will arrest pressure decline in the reservoir, due to subsurface challenges and uncertainties, artificial-lift is considered a key project requirement during the expected field life. Initially, reservoir water salinity is expected to contribute to an increased risk of salt precipitation and related flow assurance concerns as the water flood approaches the production wells. In addition, expected producing conditions are considered to be extremely corrosive. This paper will provide a summary of the expected field conditions, water flood project background and key artificial-lift application challenges including the proposed conceptual well completion designs to support the field development. A summary of artificial-lift selection, design and implementation strategy will be explained including objectives, scope and results of the recent jet-pump field trial. Finally, a brief summary of the key conclusions and plans forward will be shared.
- North America > United States (1.00)
- Asia > Middle East > Oman (0.62)
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (0.48)
The oil production wells and a water source well at Situche Central field will require artificial lift as planned with the subsurface basis of design. Artificial lift for the oil producers is required to maximize ultimate recovery and maintain oil production with increasing water cut. The main goal for Situche Artificial Lift is to provide a lift system that is efficient, the least complicated and robust enough to survive Situche downhole conditions for a minimum 2 ½ years. Such a lift system would be safer (less rig time for pump repairs and less equipment handling and transport) and have the least impact on the environment. Situche Central is a seven well development expected to be sanctioned in Q1 2013, with first oil in 2015. The successful development of Situche Central requires the re-completion of the two existing exploration wells and the drilling of two additional oil producers and water handling wells. This is the Phase 1 development.
- South America > Peru (1.00)
- North America > Canada > Alberta (0.28)
- South America > Peru > Marañón Basin > Situche Central Field (0.99)
- South America > Peru > Marañón Basin > Morona Block > Situche Central Field (0.99)
- South America > Peru > Marañón Basin > Block 64 > Situche Field (0.99)
- South America > Peru > Marañón Basin > Vivian Formation (0.98)