Agrawal, Nitesh (Cairn Oil & Gas, Vedanta Limited) | Chapman, Tom (Cairn Oil & Gas, Vedanta Limited) | Baid, Rahul (Cairn Oil & Gas, Vedanta Limited) | Singh, Ritesh Kumar (Cairn Oil & Gas, Vedanta Limited) | Shrivastava, Sahil (Cairn Oil & Gas, Vedanta Limited) | Kushwaha, Malay Kumar (Cairn Oil & Gas, Vedanta Limited) | Kolay, Jayabrata (Cairn Oil & Gas, Vedanta Limited) | Ghosh, Priyam (Cairn Oil & Gas, Vedanta Limited) | Das, Joyjit (Cairn Oil & Gas, Vedanta Limited) | Khare, Sameer (Cairn Oil & Gas, Vedanta Limited) | Kumar, Piyush (Cairn Oil & Gas, Vedanta Limited) | Aggarwal, Shubham (Cairn Oil & Gas, Vedanta Limited)
The objective of this paper is to present a suite of diagnostic methods and tools which have been developed to analyse and understand production performance degredation in wells lifted by ESPs in the Mangala field in Rajasthan, India. The Mangala field is one of the world’s largest full field polymer floods, currently injecting some 450kbbl/day of polymerized water, and a significant proportion of production is lifted with ESPs. With polymer breaking through to the producers, productivity and ESP performance in many wells have changed dramatically. We have observed rapidly reducing well productivity indexes (PI), changes to the pumps head/rate curve, increased inlet gas volume fraction (GVF) and reduction in the cooling efficiency of ESP motors from wellbore fluids. The main drivers for the work were to understand whether reduced well rates were a result of reduced PI or a degredation in the ESP pump curve, and whether these are purely down to polymer or combined with other factors, for example reduced reservoir pressure, increasing inlet gas, scale buildup, mechanical wear or pump recirculation.
The methodology adopted for diagnosis was broken in 5 parts – 1) Real time ESP parameter alarm system, 2) Time lapse analysis of production tubing pressure drop, 3) Time lapse analysis of pump head de-rating factor, 4) Time lapse analysis of pump and VFD horse power 5) Dead head and multi choke test data. With this workflow we were able to break down our understanding of production loss into its constituent components, namely well productivitiy, pump head/rate loss or additional tubing pressure drop. It was also possible to further make a data driven asseesment as to the most likely mechanisms leading to ESP head loss (and therefore rate loss), to be further broken own into whether this was due to polymer plugging, mechanical wear, gas volume fraction (GVF) de-rating, partial broken shaft/locked diffusers or holes/recirculation. In some cases a specific mechanism was compounded with an associated impact. For example, in ESPs equipped with an inlet screen, heavy polymer deposition over the screen was resulting in large pressure drops across the screen leading to lower head, but this also resulted in higher GVFs into first few stages of the pump, even though the GVF outside the pump were low, leading to further head loss from gas de-rating of the head curve. With knowledge of the magnitude of production losses from each of the underlying mechanisms, targeted remediation could then be planned.
The well and pump modelling adopted in the workflow utilise standard industry calculations, but the combination of these into highly integrated visual displays combined with time lapse analysis of operating performance, provide a unique solution not seen in commercial software we have screened.
The paper also provides various real field examples of ESP performance deterioration, showing the impact of polymer deposition leading to increased pump hydraulic friction losses, pump mechanical failure and high motor winding temperature. Diagnoses based on the presented workflow have in many cases been verified by inspection reports on failed ESPs. Diagnosis on ESPs that have not failed cannot be definitive, though the results of remediation (eg pump flush) can help to firm up the probable cause.
Khadav, Sandeep (Cairn Oil & Gas, a vertical of Vedanta Limited) | Agarwal, Shubham (Cairn Oil & Gas, a vertical of Vedanta Limited) | Kumar, Piyush (Cairn Oil & Gas, a vertical of Vedanta Limited) | Pandey, Nimish (Cairn Oil & Gas, a vertical of Vedanta Limited) | Parasher, Arunabh (Cairn Oil & Gas, a vertical of Vedanta Limited) | Kumar, Sanjeev (Cairn Oil & Gas, a vertical of Vedanta Limited) | Agarwal, Vinay (Cairn Oil & Gas, a vertical of Vedanta Limited) | Tiwari, Shobhit (Cairn Oil & Gas, a vertical of Vedanta Limited)
Bhagyam is a shallow onshore field in the northwestern region of India developed by Cairn Oil & Gas, a vertical of Vedanta Limited in two different phases with over 106 oil-producers with deviations as high as 70° and Dog Leg Severity (DLS) up to 7 deg/30m. Rod driven Progressive Cavity Pumps (PCP) were selected as the primary mode of artificial lift. The produced fluid properties which included high wax content and variable fluid viscosity ranging up to 250 cP were the main drivers in the selection of PCPs. A total of 250 unique installations of PCP systems have been completed in over 100 wells. These systems have accumulated a cumulative run-time of over 150,000 days over a total period of more than 2550 days from first installation, with an average tubing-pump system run-life of 600 days.
A major disadvantage of using a rod driven artificial lift system is metal to metal wear between rod and the tubing during operation. This metal wear in rod and tubing results in string failure, increasing costly well interventions and increased system downtime. This paper will demonstrate through specific case studies how pump operating parameters and well design were optimized over time to reduce well interventions and operating expenditures (OPEX).
A centralized data base with real time data configured with a predictive analytical model and automated performance analyzer have enhanced PCP monitoring and troubleshooting. Predictive modelling has improved preventative maintenance such as preemptive rod change outs which greatly reduced the number of rod failures increasing system uptime. In conjunction with joint industry program, detailed root-cause analysis supported with Dismantle Inspection and Failure Analysis (DIFA) laid the foundation for operational and design improvements in PCP operated wells.
Some of the recent improvements employed in system design for PCP operated wells are: Installation of through tubing PCP on an insertable anchor/pump sitting nipple Installation of packer with completion string Use of peened rods with molded guides Snap-on and spin thru guided rods Installation of externally flushed hollow rod string Replacement of conventional vam top tubing with boronized tubing Installation of high volume PCPs.
Installation of through tubing PCP on an insertable anchor/pump sitting nipple
Installation of packer with completion string
Use of peened rods with molded guides
Snap-on and spin thru guided rods
Installation of externally flushed hollow rod string
Replacement of conventional vam top tubing with boronized tubing
Installation of high volume PCPs.
Agarwal, Shubham (Leste Aihevba Cairn India Limited) | Panigrahi, Nishant (Leste Aihevba Cairn India Limited) | Ranjan, Ashish (Leste Aihevba Cairn India Limited) | Nekkanti, Satish Kumar (Leste Aihevba Cairn India Limited) | Bohra, Avinash (Leste Aihevba Cairn India Limited) | Kumar, Piyush (Leste Aihevba Cairn India Limited) | Vermani, Sanjeev (Leste Aihevba Cairn India Limited) | Kumar, Sanjeev (Leste Aihevba Cairn India Limited) | Agarrwal, Vinay (Leste Aihevba Cairn India Limited)
Bhagyam field is a shallow onshore field in Northwest India. The field development includes 150 production wells with 40 plus injection wells. The crude is sweet & light oil (27 Deg API) with 30 % wax content and a varied viscosity from range 50-450 cP. The Wax appearance temperature is ~ 2° C lower than the reservoir temperature of 53° C which impacts the completion design and affects the flow assurance of the field.
In recent times, the field production has been impacted by frequent work-overs in the field. The run life of the PCP systems, which was impacted by tubing punctures that arose from substantial rod-tubing contact loads, had reduced drastically from ~ 500 days to 259 days. The objective of this paper is first to analyze the drastic reduction in the run life of the Bhagyam PCP systems and then provide design changes which when implemented increased the run life of the PCP system.
The paper describes the measures taken and the design changes made to limit the system failure due to failed tubing and increase the run life of the system back to 500 days and will allow the readers to understand, in detail, the various types of problems that were encountered in operating PCP wells, the methods that were used to analyse the PCP failures, and new completion design that help to alleviate the problems to significantly improve the Bhagyam PCP run-life.
Khadav, Sandeep (Cairn India Ltd.) | Kumar, Rakesh (Cairn India Ltd.) | Kumar, Prakash (Cairn India Ltd.) | Kumar, Vivek (Cairn India Ltd.) | Deo, Aniket (Cairn India Ltd.) | Kumar, Piyush (Cairn India Ltd.) | Kumar, Sanjeev (Cairn India Ltd.)
This paper uses case studies to showcase the techno-economic impact of insert anchor and portable foundation on the development of marginal fields. Case studies are also included for unconventional surface pumping unit – Linear rod pump and hydraulic rod pump in the development of multiple wells from a single wellpad.
Cairn India Ltd. is developing the southern part of its RJ-ON-90/1 block consisting of multiple geographically dispersed marginal fields, with small oil pool and varying crude properties. These fields consist of wells from exploration and appraisal era (some as old as 20xx[AD1]) completed for a natural lift with no provision for installing artificial lift system. Later, it was recommended to install Sucker Rod Pump (SRP) as the most suitable Artificial Lift (AL) system. Conventionally sucker rod down-hole pump is installed by running a barrel assembly on the bottom of tubing and plunger assembly at bottom of rod string. However, in an insertable sucker rod pump (ISRP), the entire pump assembly is run-in at the bottom of rod string and is landed on pump seating nipple (PSN) which was originally installed in the tubing string. Hence, installing SRP would require an expensive work-over operation.
As the oil prices dropped, the economics of work overs became less justified. Options reviewed to improve the field economics included the use of Insertable pump anchor for installation of through tubing down-hole pump in existing well. This method allows setting the down-hole pump in tubing string without any requirement of pump seating nipple. The anchor provides the flexibility of pulling out and re-installing pump with the new or redressed system in case of pump malfunction or pump size modification etc. Extended application of insert anchor includes flow-back of hydraulic-fractured wells and extended well testing in exploration fields. It provides the flexibility of changing pump size based on reservoir response at the later stage. The multiple set-reset mechanism of insert anchor enables identifying tubing leaks and setting the pump above it.
A portable concrete foundation against the conventional concrete base used for surface unit erection provides the flexibility of transporting the foundation between different locations. The foundation can be de-mobilized while placing the work-over rig, which otherwise requires disassembling fixed foundation. The same foundation can be used at multiple well sites saving on the cost of construction and reduced lost production time.
On multi-well welllpad system, erection of conventional surface pumping unit on adjacent wells came as big challenge due to space constraint between the wells. Moreover, in the case of any well intervention like work-over, rod change etc. the nearby units requires to be disassembled adding to oil loss. Considering these problems operator decided to look into unconventional surface pumping unit e.g linear rod pump and hydraulic rod pump for the well pad systems.
Verma, Sumil Kumar (Cairn India Ltd.) | Ojha, Shiv Prakash (Cairn India Ltd.) | Jha, Mihir (Cairn India Ltd.) | Singh, Aditya Kumar (Cairn India Ltd.) | Kefford, Paul (Integrated Production Technologies Ltd.) | Kumar, Piyush (Cairn India Ltd.) | Tandon, Rohit (Cairn India Ltd.) | Kumar, Sunil (Integrated Production Technologies Ltd.) | Prasad, Dhruva (Cairn India Ltd.) | Singh, Manjit Kumar (Cairn India Ltd.)
The Mangala field, located in Rajasthan, India, is characterized by multi-Darcy sandstones, containing waxy and viscous crude oil from which most of the production is being lifted using jet pumps. This is one of the largest applications of hot water jet pumping in the world. The earlier works presented on jet pumping by the operator highlight pump screening, design, monitoring, and operational challenges (Chavan et al-2012 and Singh et al-2013).During the jet pump design work over the years, it was observed that the field results were not matching with the design particularly for wells with relatively high free gas at the pump intake. It was realized that the physics of multiphase flow in critical flow conditions was not captured fully. This paper highlights the new approach taken to model jet pumps based on the theory presented by R.G. Cunningham (ASME, JFE 1995) which explicitly captures the effect of free gas entering the pump and the onset of critical flow. The approach taken to analyze the well and jet pump performance firstly involved evaluating each part of the well independently (sand face to pump suction, flow through the jet pump, and flow from the jet pump to surface).The availability of downhole gauges in a number of the Mangala wells allowed each component of the well performance to be analyzed and validated in isolation. A final complete mathematical model of the entire well was then developed to allow predictions of the hydraulic performance of the jet pumps to be made. This paper presents the above methodology and validation of results through field trials in the Mangala wells.
Jet pumps are widely used as a form of artificial lift due to numerous advantages like the absence of reciprocating parts which allows tolerance of power and a viscous production fluid can be produced. Another advantage is the compactness of working section and ability to attain variation in liquid rates with minimal variation in jet pump design. Disadvantages include the cost of infrastructure associated with requirement of high pressure power fluid which needs to be pumped downhole and increase in the liquid handling capacity required at plant level.
In the Mangala field where even the downhole flow assurance of the produced crude is a challenge due to the high wax content, jet pumps provide down-hole flow assurance by utilizing hot water as power fluid. They are also very convenient to install and retrieve with no workover cost required. These features and others as mentioned by Chavan et al. (2012) led to the field-wise use of jet pumps in Mangala.
Bhagyam field is an onshore, shallow field containing light sweet oil (270 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) ~2o C lower than the reservoir temperature of 530 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 850 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 1st 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 2nd 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.