The use of artificial lift equipment for oil production in onshore reservoirs is becoming increasingly more important to help sustain the production rates of declining oil fields. Oil field producers therefore depend on the efficient operation of the artificial lift equipped and it is becoming increasingly more important to ensure maximum uptime of the equipment for the continuous production of oil. One of the widely used methods for artificial lift is using Electrical Submersible Pumps to produce high volumes from deep oil wells. The ESP is a very effective method of artificial lift due to its unique characteristic of having the complete pump assembly and electrical motor submersed directly in the well fluid. This however requires a complex technical design of the pump and electrical motor to ensure safe operation several thousand feed below surface. It is therefore necessary to implement systems that can monitor the pump operation and notify the operator of events that will result in failure of the equipment. Typically, ESPs are connected to SCADA or other distributed control systems to provide supervisory and control functions for their effective operation as well as for operational visibility. Today, many diagnostic methods are available to determine the health and status of an ESP system by making use of that functionality in its automation system. However, while these methods can provide insightful analysis of problems, they usually require constant monitoring of a human operator who is able to react in time to alarm notifications or implement corrective action. The correct operation of the ESP largely depends on the decisions made by the ESP field operator and his ability to effectively control the ESP fleet based on his experience. The complexity of the operator’s task increases with the size of the of ESP fleet that the operator must manage at any given point in time. But this situation is changing, with efforts being made to reduce the dependency on the human operator by implementing digital support systems. With recent advances in artificial intelligence (AI) combined with the new Internet of Things (IoT) technologies, it is possible to effectively use data-driven analytics fueled by large data sets to assist the operator with the task of operating ESP fleets. In particular, AI technology that involves deep learning and neural networks can be extremely effective in detecting abnormal behavior of complex physical systems such as ESPs, based on the data gathered from the system, providing decision support for remediating or managing the causative issues. One of the primary advantages of using AI technology is its ability to detect abnormal behavior in complex systems. Such an AI system can be implemented to monitor ESP systems using the real-time process data from the Supervisory system and then using a neural network model identify abnormal ESP pump behavior. The paper discuss how such an AI based anomaly detection systems can be used in a extended form to implemented an autonomous surveillance system which can monitor and entire ESP fleet. The purpose of the autonomous surveillance system is to support the operator in his supervisory tasks by doing the selection and prioritization of ESP units that requires operator attention. This paper is a continuation of an earlier paper which discussed the possibility to implement a predictive maintenance system for ESPs using AI. This paper further elaborates the implementation of an autonomous surveillance solution for ESP systems using the predictive maintenance solution and explain how it can be implemented using AI technology in combination with a cloud-based IoT platform.

The paper describes the feasibility of revisiting old sands, for improving the recovery factors and enhancing production, which otherwise were already abandoned. The paper also outlines the systematic methods for predicting the onset of liquid loading in gas wells, evaluation of completions for optimization and comparison of various deliquification techniques. ONGC is operating in two gas fields in eastern and western regions in India. Earlier in both the fields, many sands had to be closed/isolated after the wells ceased to flow due to liquid loading in the absence of continuous deliquification. In order to predict liquid loading tendencies and identify opportunities for production enhancement, performance of 150 gas wells has been analyzed. To select most suitable deliquification technique for the present condition, all technically feasible methods have been evaluated and compared in order to get the maximum ultimate gas recovery possible. After an extensive study, 3 wells were identified in the preliminary stage and SRP was selected as the most suitable Deliquification technique. Initially, two non-flowing wells, which had ceased due to liquid loading and were about to be abandoned, were selected. After SRP installation and sustained unloading of water for about 30 days, these wells started producing 12000 SCMD gas. In the third well, one of the top sands had earlier been isolated due to liquid loading and production history indicated that the isolated sand had a very good potential. Also, production from the well was declining in the current bottom operating sand as well due to liquid loading. Encouraged by the results that deliquification had yielded in the initial two gas wells, the isolated sand interval in the third well was opened again with the aim to revive production. The well was re-completed with SRP with both the reservoirs open. Before deliquification, the well was producing about 15000 SCMD gas from the bottom sand. After SRP installation and continuous deliquification, the well started producing gas at a stabilized rate of 45000 SCMD, thereby resulting in an additional gas recovery of 30000 SCMD for nearly one year as on date. The approach of putting in place continuous deliquification techniques has not only helped in enhancing production from the existing reservoirs, but has also opened up new avenues to revisit the earlier isolated / abandoned reservoirs for possible enhanced recoveries.

The objective of the paper is to present the methodology adopted for dual artificial system modeling in Aishwariya field– an onshore oil field located in prolific Barmer Basin, India. This paper presents a conceptual and feasibility study of combination of Jet pump (JP) and Electrical Submersible Pump (ESP) together as means of artificial lift for production enhancement in a well. It discusses the workflow to model a well producing on dual artificial lift (ESP producing in combination with Jet-Pump) via industry standard software and demonstrates the same with a successful case study. Requirement of ESP change outs to restore/enhance well production in cases such as undersized pumps, pump head degradation requires an expensive work-over. However, an option for secondary additional lift (JP) installation along with primary lift (ESP) in completion system can eliminate the costly wok-over requirement if both lifts can operate simultaneously. The procedure to model the dual artificial lift (JP and ESP) has two major components: a) Psuedo IPR at ESP discharge node and b) Standard JP modeling using pseudo IPR. Pseudo IPR is generated by modifying well specific IPR using ESP pump curve for a specific frequency. The down-hole ESP pump intake & discharge pressure sensors help calibrate the model accurately for further prediction. The existing completion in the Aishwariya field is ESP completion with the option of JP installation in cases of ESP failures as contingency. Moreover, jet pump can be installed using slick line with minimum well downtime (∼ 6 hrs). Therefore, installing and operating the Jet pump above a running ESP will not only increase the drawdown but will result in production enhancement with minimal cost. Novel Technique: No standard industry software can help model such dual lift systems with ease. The in-house developed workflow allows engineers to successfully model such complex lift scenario for routine production optimization and well surveillance activities.

Project deliverables included gravel foundation preparation, concrete foundation installation, equipment reception and installation of conventional beam pumping units at 660 production wells in a remote field in Kuwait with a deadline of six months from equipment arrival. Equipment shipments schedules were sequential and therefore an execution strategy was required to successfully meet the project deadline. This paper describes the field operations strategy devised and adopted to successfully meet the deadline. A temporary operations base was set up at the remote field for coordination, equipment reception, inspection, consolidation, pre-assembly and dispatches. Operations were divided into six parallel processes as follows: Equipment logistics Gravel foundation preparations Concrete foundation installations Unit Pre-assembly Pre-assembled units dispatches Final unit installations Daily output targets were set for each process prior to the commencement of operations. Heavy machinery, manpower and tooling requirements were defined for each process to meet the daily output targets. Progress was monitored daily and subsequently resources were scheduled and utilized to achieve the daily output targets. Setting up of a temporary operations base at the remote field along with daily coordination of resources resulted in reducing equipment’s offloading, transportation and installation cycle times, which led to increased operational efficiency and reduced logistics and operations costs. Division of operations into parallel processes helped in tracking the progress of each operation individually, thereby providing over all control in management of operations. By pre-assembling the beam pumping units at the operations base before dispatching the individual unit, installation time was reduced by 50% when compared to a typical beam pumping unit installation. Daily output target setting helped in defining the resources required to meet these targets. As the operations progressed, daily monitoring of all processes resulted in identifying opportunities to improvise operations and subsequently the daily targets were revised to increase output for each process without exceeding the resources which resulted in time and cost savings. Adopting this execution strategy concluded in successful and efficient completion of the project deliverables as follows: Gravel foundation preparations were completed in 133 work days Concrete foundation installations were completed in 121 work days Beam pumping unit installations were completed in 103 work days This field operations strategy for installing conventional beam pumping units at 660 production wells within six months can be considered as a reference for successfully and efficiently completing future large-scale beam pumping unit installation projects at remote locations in a limited time frame.

This paper discusses a case study of one of the onshore field of ONGC where while processing well fluid, frequent surge has been observed leading to shutdown of the SDVs creating severe operational problems and loss of production. It was imperative to find out the problematic wells/lines located in clusters which contribute for surge formation and mitigation approach with minimum modifications. A transient complex network of sixty five wells flowing with a different lift mode such as intermittent gas lift, continuous gas lift etc were developed in a dynamic multiphase flow simulator OLGA. Time cycle of each well were introduced for intermittent lift wells. Simulation study reveals pulsating transient trends of liquid flow, pressure which was matched with the real time data of the plant and hence confirms the accuracy of the model. After verifying the results, different scenarios were created to determine the causes of surge formation. After finding the cause, a low cost approach was considered for surge mitigations. An integrated rigorous simulation was carried out in OLGA, by feeding more than 12,000 data points to obtain model match. Several scenarios were also created such as optimization of lift gas quantity, optimization of elevation and size. Trend obtained after each scenario was pulsating behaviour and it matched with the real time data appearing in the SCADA system of the field. After rigorous simulation with each scenario, it was established that the cause of surge forming wells/pipelines. Once the root cause of surge has been confirmed then quantum of liquid generated due to surge was determined. Adequacy checks of the existing separators were carried out to estimate the handling capacity of the existing separators at prevalent operating condition. After adequacy check it was found that existing separators cannot handle the surge generated in that time interval leading to cross the high-high safety level, resulting closure of shut down valve (SDV). After establishment of root cause of the surge, a low cost solution with small modification in pipelines and control system/valves was adopted to arrest the surges. It was first of its kind simulation carried out for a huge network of wells/ pipelines by feeding more than 12,000 data to analyze the surge formation cause and capture its dynamism owing to wide array of suspected causes. This will help to address the challenges of efficiently reviewing the entire pipeline network while designing new well pad/GGS and will also help to arrest surge by adopting a low cost solution wherever such situation arises.

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.

27 gas lift wells of an Indian Offshore field were studied for feasibility of conversion of Gas lift mode to ESP. The wells have good productivity indices ranging from 1 barrel /day/psi to 6.9 barrel /day /psi. However, the production challenge was to operate these wells in a region where bubble point pressure was higher than the formation pressure itself and thus posed problem of gas evolution at the wellbore. During ESP operation in High Gas Volume Fraction (GVF) regions, extreme difference in the densities of the liquid and gas lead to a low pressure area in the Impeller during the pumping operation across the stages of ESP, resulting in gas accumulation. Free gas in these stages displaces liquid and lowers down the volumetric efficiency of the pump. In the past, 13 offshore wells were installed with ESP and many of these ESPs failed. Their failure analysis was used as a guiding light for designing successful ESP solution for other 27 candidate wells of the same Offshore field. Different methods & practices for handling gassy wells were studied and their application was analyzed. This study was aimed at finding solutions to mitigate the effect of gas interference in ESP while enhancing the production from the wells. Moreover, the paper also draws a strategy for future ESP pilot projects in high GVF fields.

Panna field is located in the western offshore region of India and produces oil and gas from Middle Eocene and Early Oligocene Bassein limestone. Production is taken mostly through 3 ½" or 4 ½" tubing through a packer set in 7″ liner. The Panna-Mukta-Tapti Joint Venture (PMT JV) took up a plan to revive wells addressing well integrity issues and limitations associated with old completion jewelry for increasing the production. Work-over campaign was planned for four wells on PB and three wells on PC platform to enhance production. The plan was to cut and retrieve the old completion and tubing above the 7″ permanent packer and install improved completion, having facilities of Permanent Down Hole Gauges (PDHG), Gas Lift Mandrel (GLM) and Chemical Injection Mandrel (CIM) through an additional packer set in 9-5/8″ casing. In line with two barrier philosophy, two plugs were set inside the production tubing, one at TRSSV (shallow-set) and another one below the production packer (deep-set). The plug below the production packer doubled-up to also hold back the workover fluid, which may have hampered the productivity of an already sub-hydrostatic reservoir, if losses occurred. However, at the end of workover operations, the retrieval of this deep set plug could not be done even after various attempts and spending valuable rig time. This problem was faced with three out of the first four wells, which proved to be a challenge and forced the team to devise a new strategy for remaining wells. At this point, an ingenious solution was devised to employ Plasma Based Punctures (PBP) to puncture the tubing in the limited space between the packer and the deep set plug to kick back the wells into production. Rig based PBP operations were carried out on two PC wells and Rig less PBP operations were carried out on three PB wells to get them online post work over operation. This resulted in saving several hours of rig time as the deep set plugs could not be retrieved in the conventional planned slick line operations. This paper intends to highlight the challenges faced, and how PBP proved to be the optimum solution, by simplifying operations and ensuring the timely delivery of production. The PBP operations proved viable through savings on energy, resources, time and cost associated with work-over jobs. The potential savings were roughly 780,000 bbls of oil which were significant for the aging asset. It is therefore, a potent alternative to other costly solutions in a scenario that often fails to deliver objectives, as happened in this campaign.

Bhagyam field is located in the prolific Northern Barmer Basin in Rajasthan, India. It has nearly 110 producers and some of these wells have limited pressure support and are geologically distinct from the rest of the field. These wells are flowed intermittently according to a pre-defined cycle based on flowing bottom-hole pressures to optimise their production. Various stimulations have been attempted to increase near wellbore productivity. However, these have largely been unsuccessful. A further restriction is posed by the completion of these wells on Progressive Cavity Pumps (PCPs) as the artificial lift method which inhibits the use of acids and aromatic compounds. This paper illustrates the successful trial of surfactant stimulation in increasing the productivity of these wells. Surfactants were considered as an alternative technique for stimulation as they pose no harm to the PCP elastomers. In addition to this, they help alter the wettability in the mixed wet to oil wet reservoir of Bhagyam field. The stimulations were designed to get the maximum penetration and were bull-headed from surface. This paper also discusses the unsuccessful stimulations carried out prior to field trial of surfactant stimulations and the studies done in the field to understand the damage mechanism behind low productivity/productivity decline. More than 10 wells (both low PI wells and intermittently flowing wells) have been successfully stimulated with surfactants till date in the field and have helped substantially in sustaining the overall field production.

This paper provides the design and operating considerations for Progressive Cavity Pumping (PCP) systems in Coal Bed Methane (CBM) wells based on field experience and illustrates their optimization with case studies of C-Fer software simulation and field trial. The challenge is to effectively lift water throughout the CBM well life with the same PCP system while accommodating pressure head increments and flow rate decrements with time. This paper presents a novel idea to optimize PCP system at different stages of CBM well life with minimal cost implications to the company. The major inputs for artificial lift design are seam depth and well productivity, while PCP head and flow rate, down-hole string sizing and motor sizing are the required outputs. To take a case study of PCP system optimization, we have Well – A, where the bottom perforation is at 600 m and the water production is expected to start with a peak of 150 m 3 /day at 100 m water level and reach 100 m 3 /day at 600 m water level in about 10 months. The authors chose a system with flow capacity of 76 CMD at 100 RPM and lift capacity greater than 800 m. Tubing size of 2.875″ is chosen and sucker rod size of 1″ is chosen. The surface motor of 22 kW is selected based on the maximum power required by the PCP system at the maximum lift condition. The process of selection is depicted clearly in this paper. Although, the PCP system is designed as per the design considerations, the maximum RPM in the initial CBM well life may be limited by the pulley ratio (driven pulley diameter: driving pulley diameter) while the torque imparting capability of the motor at later stages may be limited by the motor frequency at the later stages of the well life. Hence, simulations for different run scenarios (water levels and flow rates) were done in C-Fer PC-Pump software for two cases taking Pulley Ratio as 4.74 and 6.22. The authors have presented trends comparing important parameters namely Fluid Level-Surface Motor loading, Fluid Level-Maximum Rod Torque and Fluid Flow Rate-Pump Speed. Based on the interpretation of these results, it was decided to experiment with two different driving pulleys for changing the pulley ratio during the well life to optimize the PCP system instead of upsizing the motor. This field trial was successfully conducted in Well – B and the parameters and the results are clearly depicted in the paper. Changing the pulley ratio over CBM well life will fulfill the torque and power requirements at the required pump RPM with significant cost savings by eliminating the need to install a new motor.

The paper discusses a case study of unconventional installation of an Insert Progressive Cavity Pump (IPCP) in a well with 4-1/2" production tubing without a Pump Seating Nipple (PSN) in place. The installation was unique application as no flexisert anchor was available for 4-1/2" tubing size which are commercially available for 2-7/8" and 3-1/2" tubing sizes. This unique installation while producing slightly lower than conventional PCP was the first of its kind, fit for purpose and helped in reviving a well without conducting a costly workover for changing out the PCP. This installation further opened an avenue for successful intervention for many other wells completed with conventional PCP without a PSN, and helped in saving a workover each time. Another innovative solution to delay workover was implemented in the field in which a PSN for I-PCP was installed during the intial completion itself in anticipation of tubing integral PCP stator failure before the tubing failure necessitating a full workover.

Harsh wellbore environments reduce the run-life of an Electrical Submersible Pump (ESP), adversely affect casing integrity and require expensive ESP replacements that also subject the well to formation damage due to invasion of the kill-fluid used for well-control. Under such severe operating conditions, an ESP pod system coupled with an isolation packer and a fluid loss valve (FLV) can increase the pump run life, reduce downtime and improve well integrity. Pod system is a specially designed capsule to encase the ESP in an enclosed and sealed environment. The Isolation-packer along with the fluid loss valve (FLV) provides mechanical isolation at the sand-face during ESP replacement operations and protects the formation from the invasion of damage inducing kill fluids. During production, the system safeguards the casing from corrosive well fluids and eliminates damage to the power cable from pressure cycles; fluid enters through the bottom of the pod system and is lifted through the tubing without coming in contact with the casing above the packer. This paper describes a case history on the planning, in-house design, completion and post-installation performance of an ESP pod system implemented as a pilot study for a well in Humma field, Wafra Joint Operations –Partitioned zone. A cost effective and case specific solution was achieved by assembling the various ESP pod components together after researching the various vendors available. The objectives of higher production, improved recovery, and reduced lifting costs were achieved since installation, in the last five and a half years of ESP run-life. The pod system proved to be a customized solution for this well which was previously functioning with diminished pump performance and suffered from frequent failures that led to critical well control issues encountered during pump replacement. ESP is a preferred mode of artificial lift in the Humma field to tackle higher production rates from deep reservoirs. The post installation performance of the ESP pod system has laid the guidelines to achieve uninterrupted and commercially viable production from similar reservoirs that have sub-hydrostatic reservoir pressure and hostile downhole operating environments not conducive for a standard ESP installation and operation.

The ONGC operated XYZ field is the farthest oilfield from shore located in western offshore of India. Based on the remoteness and marginal nature of the field, it was developed by deploying an Early Production System and brought on production in 2006. Concurrent exploration and development activities resulted in horizontal & vertical growth of the field, nearly doubling the in-place reserves. Subsequently, the field development strategies were revised and the Early Production System was replaced with FPSO in 2013. Post FPSO installation, back pressure in the field increased leading to sub-optimal production from the self-flowing wells necessitating early installation of artificial lift. The reservoir is multi-layered limestone in a depth span of 2100–2850m. Reservoir pressure is almost hydrostatic and temperature ranges from 120–140°C. The crude is light and highly under saturated with bubble point pressure less than 100 kg/cm 2 . With low production GOR (~40 v/v) and no nearby source of gas, possibility of using gas lift was eliminated. However, highly under saturated crude with favourable reservoir conditions made it an attractive proposition to install ESP as artificial lift in the field. ESP installation campaign kicked off in May-13. The campaign suffered initial setbacks in the form of premature/frequent ESP failures resulting in production downtime. Completion of the new wells with predesigned ESP since inception led to sub-optimal production performance of some wells. The early ESP failures warranted a comprehensive review of ESP design and installation strategies followed in the field. Accordingly, accelerated mid-course corrections were made and new strategies were formulated for optimized ESP design. ESP installation methodologies were also reviewed to minimize operational hiccups. This was followed by close monitoring of ESP performance for further optimization opportunities in accordance with dynamic reservoir conditions. The performance of ESPs designed and installed using revised methodology was in line with the expectations. With improved ESP design and installation practices, sustained production could be realized and the field witnessed turnaround in production with peak oil rate of 32000 bopd through 28 wells in Feb-15. The paper discusses lessons learnt while overcoming the challenges and procedures implemented in design, installation, operation and monitoring of ESPs in XYZ field which led to a successful endeavor to revive the field to its anticipated potential.

Single Point Gas Lift (SPGL) is preferred in subsea wells due to its certain advantages over conventional completion with unloading valves in meeting the aim for no intervention, pressure barrier requirements etc. Current paper presents a flow assurance study of an SPGL system in a deepwater field in India. The development strategy envisages clustered subsea wells with common flowlines connected to an FPSO about 12 km away. Requirement of gas lift is envisaged from mid-life due to expected depletion in reservoir pressures and increase in water cut. Subsea gas lift in deepwater environment typically requires higher injection pressure to lift from desired injection depth. The gas lift, flowline and riser system is expected to operate over a wide range of conditions in terms of fluid composition, pressure and flow rates. Optimum design and operation of an SPGL system under such conditions is a challenge. Integrated dynamic modelling from down hole to host facility at the pre-FEED stage can provide valuable inputs for system design and operability. The impact of various gas lift parameters like orifice size, setting depth, kick off pressure and operating injection pressure on the system has been studied. The field is having waxy crude with high pour point of 36°C with gelation propensity during long shut downs. The paper also brings out the operability windows during start up, turndown, shutdown, restart etc. and their impact on topside design. Transient modelling has been used to invetigate threats to system integrity due to high velocities of fluid through orifice, low temperature limits due to JT cooling, pressure surges into the production line resulting in large slugs arriving at FPSO. Slugging in riser may lead to process shut downs due to the pressure and rate variations resulting in loss of production. Design and optimization of the SPGL system is also aimed at increasing total production by avoiding process shut downs due to well instability and pipeline slugging.

Progressive Cavity Pumps (PCPs), if properly sized, can greatly improve a well's deliverability and run-life. As a result, PCP sizing for a large number of wells can be instrumental in a production optimization program. This paper presents a quick look methodology adopted in the Bhagyam field to better understand PCP system performance and to accurately predict pump deliverability under a wide range of downhole conditions for more than a hundred wells. Using nodal analysis, this paper presents the procedure used to select optimum pump size and well fluid rates from well inflow and outflow performance. The paper also presents a correction factor for the effect of viscosity on pump performance and uses the corrected pump performance curves to model the expected liquid rate from a well. The solutions obtained with the analyses have been validated against actual Bhagyam well test data and have proved to be fairly consistent. This procedure has not only been a useful tool for pump selection and performance monitoring but has also made a significant business impact in terms of incremental oil gain.The methodology quickly provides reasonably accurate solutions for pump selection and allows evaluation of real time pump parameters to optimize PCP under varying field conditions.

This paper explains how the real-time surveillance helps improving runlife, uptime and reducing production deferment of Electrical Submergible Pumps (ESP) of SG-300 offshore platform wells of Gulf of Suez Petroleum Company (GUPCO). The implementation of a robust suerveillance workflow together with real-time surveillance and alarm notification system has shown a good contribution to increase ESP runlife via preventing the ESP from being misoperated outside its recommended operating conditions and experiencing excessive stress, reduce start/stops and downtime, reduce production deferment, and improve downhole chemical injection program for scale inhibition. This is being done via classification of alarms and on-fly diagnostics of main root causes that helps to promptly identify remedial actions and/or recommendations.

Worldwide more than two thirds of the oil wells are placed on some kind of artificial lift, mostly on sucker-rod pumping, ESP, or gas lift. Because of the great number of installations it is extremely important that they operate under optimum conditions. Even small changes in operational efficiencies can significantly increase operational expenditures, so optimization of the energy efficiency has a great impact on profitability of oil production. The presentation deals with establishing the most energy-efficient operation of artificial lift installations. The aim of the optimization is finding the minimum operational costs while producing a prescribed liquid rate from the well, i.e. attaining the maximum power efficiency. Three forms of artificial lifting are studied: sucker-rod pumping, ESP, and gas lifting. The power efficiency of any artificial lift system is defined by the relation of the useful power used for fluid lifting and the total input power. The useful hydraulic power is defined by the change of potential energy of the produced fluid, while the total input power can be calculated. Analysis of the power flow in rod pumped wells shows that maximum efficiency is reached with the proper combination of pump size, polished rod stroke length, and pumping speed. The installation's power efficiency is primarily determined by the choice of the pumping mode. The power efficiency of ESP installations is shown to reach a maximum when using a motor and a pump with the maximum efficiency while minimizing the power losses in the electric cable. Optimum design of continuous flow gas lift installations involves NODAL analyses and finds the combination of tubing size, injection and wellhead pressures, and flowline size that ensures the minimum compressor power requirements.

The Falah field offshore Dubai consists of four satellite platforms and is mostly produced by gas lift. High pressure lift gas is received from the main SWFateh field and the produced fluid and gas after a two-phase separation are returned to SWFateh through long sub-sea pipelines. The system is constrained both on the gas lift supply and surface production networks. The conversion of two of the major gas lift producers to electric submersible pump (ESP) has helped de-bottleneck the Falah system. The main objectives were to increase drawdown in these wells using ESP and to reduce the load on the gas lift and production systems. Both of these objectives have been successfully achieved. This paper will describe the system constraints, the options considered and the economics associated with each option. The modeling work that helped the justification for the ESP installation will also be described. The selection of well candidates was an important criterion for success. From a reservoir perspective the goal was to achieve improved oil recovery with increased drawdown. From a facility perspective the wells were selected at the farthest (FB) platform that had the minimum gas lift pressure in the field. Commissioning of the ESPs has reduced the gas load on the system and the production system pressures have decreased as a result. Gas lift operating depths would be deepened in some of the Falah wells, taking advantage of the increased gas lift header pressure now available. The use of ESP for de-bottlenecking a gas lifted field is an excellent example of production system optimization. This demonstrates how a different type of artificial lift can be effectively used to improve the productivity of a field that uses one type of artificial lift.

The development of oil and gas fields in recent years has become more technically and economically challenging. Interdisciplinary interaction is needed to have effective and efficient field planning. Indeed, it has been noted that field management by using integrated surface-subsurface modeling will have an extremely positive effect on production. This paper presents the interdisciplinary teamwork between subsurface and surface engineering in their efforts to construct an integrated production model for Kaji Semoga field, a large and complex onshore production field located in South Sumatra, Indonesia. The model covers about 180 wells, which are spread over 45 clusters, and surface facilities in three field processing stations. It covers all facilities from well up to the nearest field station for separating gas from oil and for compressing it prior to distributing to clusters and finally injecting the well. The model also incorporates 84 new ESP, which will be installed by the end of year 2009 to replace the existing gas lift system. The model predicts an additional oil gain of 2,500 bopd (14.7%) as a result of installing ESP. About 170,000 blpd of liquid will be produced after the ESP installation project is completed. Consequently, liquid handling in each station has become a critical issue to be resolved before all the ESPs are installed. Several operational manoeuvers have been carried out to handle the forthcoming produced liquid by utilizing the model. About 300 bopd (1.8%) of oil gain from the cluster flow diversion scenario has already been realized. Apart from the liquid handling issue, the model also highlights the future gas-lift gas requirement for the remaining gas lift wells. Several active compressors can be shut down as a result of the outcome of the model, so the operating cost can be reduced significantly. The model also identifies potential bottlenecks along the production trunkline, which can result in a potential reduction of 140 bopd. In addition, the model also identifies a potential oil gain of about 220 bopd (1.3%) if back pressure on several production trunklines can be minimized. Field engineers have benefitted from the use of this model: it can help them assess any changes or manoeuvres in the field. This is expected to add about 200 bopd (1.2%). Some of these changes and manoeuvres are being executed this year.

Kaji Semoga (KS) field has produced primarily from limestone and has until recently contained sufficient gas for gas lift usage. However, KS gas production is declining rapidly: it is estimated that by 2013 it will produce insufficient gas. As a result, some new forms of artificial lift are being considered to replace gas lift, and since the end of 2008 new ESP and HPU projects have been carried out with the aim of such a new form of lift. As a result of implementing these projects, ESP wells will be the dominant artificial lift for production wells in KS, contributing to approximately 70% of total oil production On the other hand, there are risks of downtime associated with the use of ESP. The main risks concern downhole problems, which need rig deployment, and electrical problems, which cause the ESPs to shut down. Fixng these problems may require a considerable amount of time - several days or even weeks - due to reasons such as unavailability of a rig and/or spare parts. This will inevitably result in loss of oil .production. To avoid such production loss, an ESP / gas lift hybrid system has been implemented, whereby gas lift is prepared as a backup. This hybrid system consists of an ESP unit installed along with a gas lift system in single tubing, with no packer and 1 (one) (screen orifice) gas lift valve, 1 (one) sliding sleeve door, and 1(one) complete ESP unit. All ESP wells in KS (currently 70 wells and counting) now use this configuration. The gas lift hybrid system has been used as backup during ESP downtime. This configuration can produce 35% of liquid compared to normal ESP liquid production, and as a result an oil loss of 4400 bbls was prevented during 2009.