Bhagyam is the second largest oilfield discovered to date in the Barmer Basin, India with more than 400mmb of viscous, waxy crude in place. This paper describes the evaluation, design and selection process for the use of the latest generation ICD in non-horizontal wells. Sandface completions comprise sand screens coupled with an ICD. Inflow control was highly desirable due to the oil viscosity variation, high permeability, heterogeneity and adverse mobility ratio and the fact the completions could not be easily accessed below a PCP. Oil viscosity ranges from 20 to 250cp varying with depth. The variation in reservoir thickness, produced fluid viscosity and well productivity required a field adjustable pressure drop capability in the ICD. The ICD had to perform at high viscosity and needed to be tolerant to wax and sand production. The operator's experience in nearby fields observed the benefits of ICDs for providing efficient sandface cleanup in horizontal wells. It was vital to model this system accurately however there were significant challenges as no previous examples of using these devices in non-horizontal wells could be found and the ICD completion had not been modeled in a dynamic simulator for this scale of field development. A dynamic simulation model which included the ICD completion was used to evaluate various completion options. A significant amount of work was performed to ensure the ICD was accurately modeled in the simulator. The simulations showed a long term benefit from using the ICD. To date 22 production wells have been completed with the ICD screen systems. This is one of the first applications of the latest generation ICD in non-horizontal wells particularly on a full field scale. It is also a case study of modeling the ICD completion with a dynamic simulator.
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.
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.
Significant production rate decline and a few ESP failures were observed in the Mangala field, onshore India, due to scaling. Scale inhibitor squeeze treatments were required to arrest the production decline and prevent additional ESP failures. The Mangala crude oil is extremely waxy, with a wax appearance temperature (WAT) of 62 o C and a reservoir temperature of 65 o C. This meant that prior to chemical application, fluids would have to be pre-heated to prevent wax formation and potential damage to the near wellbore area. The produced water chemistry included iron concentrations in the region of 5 -15 mg/l, which was related to the presence of significant quantity of siderite within the formation and which could have resulted in potential formation damage due to iron dissolution when applying pre-selected acid-phosphonate inhibitors. Additionally, the two main producing formations FM3 and FM 4 are produced from long horizontal wells completed with stand-alone screens. Chemical placement in the wells therefore proved to be a significant challenge, and treatments were designed to achieve placement across the water producing zones. This paper describes the squeeze chemical selection for minimisation of formation damage risks associated with treatments in this particularly challenging case study, with WAT close to reservoir temperature and the presence of reactive iron minerals. The impact that these factors had on both chemical performance and on the potential applicability of the selected chemicals is discussed. The paper also discusses pre-conditioning treatments pumped in these wells to regain productivity. The work also demonstrates how a combination of laboratory testing and treatment modelling has been used to minimise the potential for formation damage while at the same time maximising chemical treatment of the water producing zones. The detailed mineralogy and heterogeneity of the reservoir formations, the impact of production conditions and elevated iron on the performance of the selected chemicals are all described as well as the selection of alternative generic chemicals which were not poisoned by the increased iron. Initial field treatments have been conducted and preliminary results will also be presented which concur with the chemical qualification and treatment design Overview of Mangala FieldThe onshore Mangala field is located in the north-west part of India in the Barmer Basin (Figure 1). The field was discovered in January 2004. The main reservoir unit in Mangala field is the Fatehgarh group, which is a very high quality quartzose sandstone reservoir, with high net to gross, high porosity and multi-Darcy permeability. The Fatehgarh sand has been subdivided into the Lower Fatehgarh formation dominated by well-connected sheet flood and braided channel sands, and the Upper Fatehgarh formation dominated by sinuous, meandering, fluvial channel sands. Five reservoir units are recognized, named FM1-FM5 from the top downwards. FM1 and FM2 comprise the Upper Fatehgarh formation and FM3, FM4 and FM5 form ...
This paper describes the first time selection and successful application of Sliding Sleeve Sand Screens in the open hole completions of the giant Mangala field situated in the Barmer Basin in Rajasthan, India which holds ~1.2 billion barrels (bbls) of oil in place. The field is a multilayer reservoir and has waxy viscous crude with in-situ oil viscosity up to 17 cp. The field is being developed with a hot water flood for pressure maintenance and reservoir sweep. Significant production challenges include; an unfavourable mobility ratio, early water cut, sand production and high pour point. Production well completions with sand screens with sliding sleeves play an important role in the field development, providing a very flexible tool to manage production from individual sand units coupled with open hole sand control. The screens are installed as an open hole completion and swellable element packers provide annular flow control. Intervention costs are kept low, as the field is onshore and the opening / closing of the sliding sleeves are done with relatively cheap onshore well intervention via slickline. Active reservoir surveillance and management in Mangala field will play a key part in maximising reserves and production rates from the field. Sliding sleeve sand screens are an appropriate technology for the Mangala field oil wells. These screens provide options for downhole water control across the formation thus increasing well life and reducing water handling at surface. This paper describes the design and implementation of these completions and how the completions provide optimum reservoir management capability for the Mangala field.
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