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Tiwari, Shobhit (Cairn India Ltd.) | Singh, Ranjeet (Cairn India Limited) | Prasad, Dhruva (Cairn India Ltd.) | Kumar, Pankaj (Cairn India Ltd.) | Jha, Mihir (Cairn India Ltd.) | Tandon, Rohit (Cairn India Ltd.) | Singh, Aditya Kumar (Cairn India Ltd.) | Dangwal, Gaurav (Cairn India Limited)
Abstract This paper discusses the step by step procedure to identify damage mechanism and remedial treatment in horizontal wells flowing with ESP (Electrical Submersible Pump) in one of the largest onshore field Mangala situated in Barmer, Rajasthan, India. Mangala field was discovered in 2004 and was brought on production with hot water flooding in August 2009 and is currently producing at plateau rate of 150,000 bopd (barrels of oil per day). The reservoir, in general, is of high quality with multi-darcy permeability, relatively viscous (15cp) and waxy crude (wax appearance temperature only 5 deg C below reservoir temperature). The Fathegarh is the main reservoir unit which is sub-divided into FM1 (top) to FM5 (base). FM3 and FM4 are dominated by well-connected sheet flood and braided channel sands having net to gross ~80%. These massive FM3 and FM4 sands have been developed with down-dip edge water line drive water injectors and up-dip horizontal producers. These horizontals wells (lateral length >500m) are completed with screens with ICD's (Inflow Control Devices).The initial PI (productivity index) of wells has been of the order of 50–100 b/d/psi. However, with rise in water cut and increased withdrawal rate the productivity of these horizontal wells started to decline. This paper discussed the optimized production practice required to maintain optimum production rate from these horizontal wells. Due to the fact that even relatively shallow invasive near-wellbore damage may substantially impede flow; plan was prepared to identify the damage mechanism and accordingly engineer suitable remedial treatment. Envisaged damage mechanism included fines mobilization, asphaltene / wax dropouts and carbonate and sulfates scales. An inherent problem with these wells was poor acid distribution during matrix acidizing, especially due to high permeability in long horizontal sections. The low cost systematic stimulation design and placement technique resulted into the liquid PI restoration and improved ESP performance, which has been discussed in length in the paper. Introduction Mangala is an onshore oil field located in northern Barmer Basin of Rajasthan state, India. The main reservoir unit is Fatehgarh which has been further subdivided into five sub units named from FM-1 to FM-5 from top to downward. Upper Fatehgarh which comprises FM-1 and FM-2, is a sinuous, meandering, fluvial channel sands whereas Lower Fatehgarh which comprises FM-3 to FM-5 is well-connected braided channel sand. Upper Fatehgarh has been developed using deviated wells with pattern as well as peripheral injectors and lower Fatehgarh has been developed primarily by drilling updip horizontal wells with downdip peripheral deviated water injectors (Figure 1). Reservoir quality of Fatehgarh sands are excellent with porosity ranging between 21–26 % and in-situ permeability between 200 md to 20 Darcy. Mangala crude oil is waxy viscous crude with in-situ oil viscosity ~ 22 cp and wax content between 18–26% and the API gravity is 28.5. Mangala summary production performance plot is shown in Figure 2. Commercial production began in the Southern part of the field in August 2009. Mangala reached its initial approved oil production rate of 125 kbopd in 3 quarter of 2010 and was further ramped up to 150kbopd from 2 quarter of 2012 with higher withdrawal rate approvals. Hot water injection started in start of 2010.
Chavan, Chetan (Cairn India Limited) | Rao, Eshwar (Cairn India Limited) | Jha, Mihir (Cairn India Limited) | Tiwari, Shobhit (Cairn India Limited) | Graham, Gordon (Scaled Solutions Limited) | Stalker, Robert (Scaled Solutions Limited)
Abstract 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°C and a reservoir temperature of 65°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
ABSTRACT The Mangala field in the Rajasthan state of western India was the first major oil discovery in the Barmer Basin having a STOIIP of over 1.3 billion barrels in multiple stacked fluvial clastic reservoirs. It contains medium gravity (20-28 °API), waxy, viscous crude (9-17 cp) in high permeability (1-25 Darcy) clean sandstone reservoirs. Mangala field is on production since 2009 and is currently producing at 150k bopd. The field has a comprehensive reservoir Management plan (RMP). As per the RMP, an active reservoir surveillance plan of data acquisition and analysis is being continuously executed in the field. The key data acquisition included Pressure surveys, Production and injection logging, well and network modeling, Reservoir saturation logging, Interference testing, well & artificial lift parameters. Several challenges and production and injection problems were identified and were addressed in a step wise manner. The well and reservoir performance for ∼ 2 years suggested higher production capacity. Detailed well modeling and surface network modeling was carried out and it was seen that after the installation of Artificial lift, the ongoing production enhancement efforts, continuous reservoir surveillance and management, the field had capacity to produce at a plateau rate of 150k bopd. Simulation studies suggested no detrimental effects on the ultimate recovery. The plateau rate of the field was increased from approved FDP rate of 125k to 150k bopd, after due approvals and the field has been producing at this rate since April 2012. This paper presents the summary of: Data acquired during the production phase of 125k bopd Major problems identified in the field and there mitigation Well and Network Modeling Study History of field post plateau rates of 150k bopd. Challenges being faced to maintain 150k bopd
Abstract Bhagyam field is an onshore, shallow field containing light sweet oil (27° API) with low Gas Oil Ratio (GOR) (~100 scf/stb). The crude has ~30% wax content with moderate insitu oil viscosity of ~ 50–250 centipoise (cP) with wax appearance temperature (WAT) ~2° C lower than the reservoir temperature of 53° C. With water production, it was initially expected that viscosity of production fluid will rise upto 3000 cP due to emulsification. Rod driven Progressing Cavity Pump (PCP) system was selected as artificial lift for the field development considering low GOR and relatively high fluid viscosity. To ensure flow assurance of the high WAT crude, various methods such as annular hot water circulation, heater cable, vacuum insulated tubing (VIT) etc were considered. Based on the analogue Mangala field, which is located in the same license area, it was decided to utilize annular hot water circulation as the downhole heating methodology as it provided a significant completion design similarity with previous installation and operational experience. This completion involves running Colied Tubing (CT) clamped to the main production tubing as a secondary string. The main production tubing with PCP stator is stabbed in a production packer for downhole isolation.Hot water is circulated at 85° C down the coil taking returns through the annulus. This arrangement ensures temperature of the fluid inside the main production tubing is maintained higher than the WAT at all times. In the 1 phase of field development, wells completed with PCP and have been successfully operating for ~ 2 years meeting requirement of flow assurance & PCP run life. However, PCP efficiency was lower in high GOR wells, as downhole gas separation was not possible. For the 2 phase of development, alternate completion designs which can mitigate the downhole flow assurance challenges and at the same time open up the annulus similar to a conventional PCP application were considered and finally hollow rod driven PCP design was selected as the most suitable method. The paper details PCP application in Bhagyam field during the first two phases of development, installation & operating practices, lessons learnt & overall system performance.
Abstract This paper discusses the performance monitoring and optimization of large scale jet pumping in Mangala field, one of the biggest onshore fields in India. Mangala field is characterized by multi-Darcy sandstones, containing waxy and viscous crude oil. Currently, the field is producing at plateau of 150,000 BOPD. The base development plan for the field included hot water flooding; this also makes water heated up to 80 °C available at the well pads as power fluid for jet pumping. Jet pump was selected as the preferred artificial lift method in deviated wells, as it addresses all flow assurance issues arising due to high wax appearance temperature of Mangala crude. Jet pumps provide the required drawdown for sustained liquid production both at low and high water cut. With significant number of wells operating on jet pump, it has become crucial to monitor the performance and optimize for maximum efficiency application by varying operating parameters, changing the nozzle throat combinations and making other adjustments. Currently, Cairn is monitoring the real time jet pump operating parameters on a daily basis by virtue of DOF (Digital Oil Field). DOF has not only eased the tedious task of jet pump monitoring in bulk but also has reduced the response time to any failures/damage in the pump. Liquid handling capacity of the processing plant has become crucial with increasing field water cut and more jet pump installations. Jet pump performance optimization for maximum efficiency has now started to play an important role in not only reducing the burden of the processing facility but also in improving the production profile of the wells. This paper will discuss the use of a methodology based on an in-house developed algorithm for monitoring the efficiency of the pumps, with supporting field examples. This paper will also make an attempt to analyze the effect of different operating conditions on the pump performance curves published in the literature.