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.
After 1859, sucker rod pump was invented commercially by C. E. Drake1, it was used vast majority of wells throughout the world. Thus, it became an oil symbol which comes to mind first for people even who are not engaged in this industry. Although SRPs are installed in about 90% of oil wells in USA, half of wells, 110 are installed by SRP in Adiyaman. Oil and water production is 13,000-13,500 bbl/day and amount of oil is 3,000-3,500 bbl/day.
This study explained that effects of parameters, which are related to reservoir and design, to the mean time between failures (MTBF) of pumps. In this controlled test, MTBF is dependent variable and well parameters are independent variables such as pump diameter, water cut, pump depth, stroke per minute(SPM), salinity and flow rate. These independent variables are examined one by one and completely. All data are taken from 384 well operations in 77 wells and spanned 3.5 years.
Index Terms - Sucker Rod Pumps, SRP, Run Life, MTBF, Design Parameters, Well Parameters
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  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.
This paper describes the selection, design, successful application and performance monitoring of Electrical Submersible pumps in the giant Mangala oil field and Thumbli water field situated in the Barmer basin in Rajasthan, India. Mangala oil field contains approximately 1.3 billion barrels of STOIIP 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 40% 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 100 deviated producers. ESP was selected as the artificial lift mode for the high rate horizontal producers while hot water jet pumping was selected as the artificial lift mode 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 11 horizontal producers are on ESP lift and the remaining three 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 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 detailed study and extensive evaluation was done by Talisman Energy to select the best artificial lift solution for the Situche Field in Block 64, Peru. Gas lift, ESP and Hydraulic Lift were studied. However, a New Technology, ESTSP (Electric Submersible Twin Screw Pumps- Multiphase) was selected for these sour, deep and hot wells.
This paper is part of the Define Stage document of Talisman Energy's Project Delivery System (PDS) for Artificial Lift Completions at Block 64 in Peru. Although the project in Peru is being shut down it is recommended that ESTSP be used in other complicated onshore or offshore wells.
The deep, hot oil wells, in Block 64, located in the Amazon rainforest of Peru, are a difficult environment for artificial lift. See the map on Figure 1. The Situche Central oil field would be the initial field development in Block 64.
The main goal for Artificial Lift in Block 64 is to provide a high rate lift system that is efficient, the least complicated and robust enough to survive severe downhole conditions at the Situche field. Run life, from initial pump installation, would be a minimum 2 ½ years, with no early time failures. 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.
A review of available information suggests that an ESTSP (electric submersible twin screw pump) with a PMM (permanent magnet motor) on a retrievable packer (new wells) would meet the above goals. Before deployment, this pumpset and ancillary equipment, would undergo a 3 month endurance test in a hot loop designed to simulate downhole conditions at the Situche Central Field.
This document shows the development process, information and analysis that would lead to the design, build, bench testing and deployment of a robust downhole electric pump system. These operations would occur during the execute stage of the Situche Field development. Also included is a description of the associated completion equipment required for the HPHT pump application such as power cable penetrators, a high temperature retrievable packer and high temperature gauges required for pump control.
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 Sm3/m3, 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.