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Abstract At Kuwait Oil Company (KOC) most of the ESP wells are running with downhole sensors to enhance the daily monitoring routine and for having a better knowledge of the pumps performances. However, one of the most important parameter of these ESP Wells is only known after a time period within 3-6 months: The Flow Rate. Production Tests are obtained using Multiphase Flow Testing Units which usually last between 4 and 6 hours that are also utilized to conduct some sensitivities such as choke size and motor speed changes. At Well Surveillance Group, a tailored fit model was developed from which the ESP flow rate can be estimated based on the downhole sensor data and basic fluid properties with an overall deviation below 2% (when they are compared to the results obtained from the Testing Unit). In this sense, flow rate monitoring can be performed at any time and flow testing time and associated cost can be reduced among other benefits. The method requires knowing the ESP model and total number of stages installed in the well, and then using the corresponding performance curve of the ESP model usually provided by the manufacturer, the data is processed and the calculation performed. This work aims to show how this model works, advantages, limitations, implementation status and future improvements.
- North America > United States (1.00)
- Asia > Middle East > Kuwait (0.71)
An Iterative Solution to Compute Critical Velocity and Rate Required to Unload Condensate-Rich Saudi Arabian Gas Fields and Maintain Field Potential and Optimal Production
Al-Jamaan, Hamza (Saudi Aramco) | Zillur, Rahim (Saudi Aramco) | Bandar, Al-Malki (Saudi Aramco) | Adnan, Al-Kanan (Saudi Aramco)
Abstract Saudi Arabian non associate gas reservoirs produce various amounts of condensate depending upon field and reservoir. In most cases, these wells are hydraulically fractured and at the initial stage after such stimulation treatment, each well needs to unload high quantity of the pumped fluid to ensure full potential. If the liquid starts accumulating in the wellbore during production, the well productivity will gradually decrease and eventually may stop producing. If the gas flow velocity in the production string is high enough, the gas will continue flowing and will carry the liquid droplets up the wellbore to the surface. The minimum velocity and critical gas rate (Qcrit) are therefore the determining factors while producing a well or several wells from a condensate-rich field so as to ensure the stable field production rate and maintain production plateau. An analytical model has been developed to iteratively compute the critical velocity (Vcrit) and Qcrit, for given flowing wellhead pressure (FWHP), tubing diameter, and many other reservoir and completion properties. If the FWHP is set and a certain production rate is expected of a well, the program automatically computes the pressure drop due to friction, dynamic hydrostatic head, and the bottomhole pressure. Simultaneously, both Vcrit and Qcrit to unload the fluids are calculated. If the Qcrit is above the expected production rate, a different wellbore completion is automatically selected and computation is continued until Qcrit is lower than the expected rate of the well. If this is not possible, the program will display appropriate message. Several wells from a condensate gas reservoir are analyzed from a field that has to maintain certain production potential for a given number of years. The analyses show that the wells that are producing without intervention are those that are confirmed by this model to be flowing above the Qcrit. For wells that were intermittently producing and ultimately could not sustain production were producing at rates below the critical values. Using this iterative model, those rates are automatically adjusted or new completion string is suggested to bring them back into production.
- Asia > Middle East (0.94)
- North America > Canada > Alberta > Stettler County No. 6 (0.24)
- North America > Canada > Alberta > Starland County (0.24)
- (2 more...)
Summary This paper presents electric-submersible-pump (ESP) -stage performance handling air and water in a laboratory setup. Experimental data gathered shows the effect of volumetric gas flow rate and intake-stage pressure for different rotational speeds. The presence of gas mildly deteriorates the stage performance at low volumetric gas flow rates. A sudden reduction in the stage-pressure increment is observed at this operation condition for a certain critical liquid flow rate, which marks the initiation of surging on the stage performance as mentioned by Lea and Bearden (1982). The surging initiates at lower liquid flow rates as the volumetric gas flow rate increases, which demonstrates the relationship between the surging initiation and liquid flow rate. It is also observed that the initiation of the surging moves toward lower liquid flow rates by increasing the rotational speed or the stage intake pressure. A two-phase stage-performance map was recently introduced, defining boundaries for five pump-performance regimes: homogenous, mild-performance deterioration, performance reverse slop, server performance deterioration, and nil performance (Gamboa and Prado 2011b). The current work shows that these performance regime boundaries are affected by rotational speed and intake-stage pressure.
- Europe (0.93)
- North America > United States > Oklahoma (0.29)
- Research Report > New Finding (1.00)
- Research Report > Experimental Study (0.64)
Abstract The current problem related to poor-quality control of artificial lift operational parameters can be solved by means of development and application or real-time monitoring, control and analysis systems. As one way to solve this problem, TNK-BP has implemented the real-time SRP monitoring system. The SRP monitoring system is a specialized SCADA and expert system for SRP. The system displays and analyzes the information from the controllers, gives a possibility of remote control by means of controllers on the wells. SRP controllers are installed on the well sites in order to gather and analyze the data received from the transducers for SRP monitoring and operational control. The controller technology is based on processing a dynagraph for each pump jack stroke, which enables to ensure SRP control as per the rated parameters settings, diagnose the SRP condition, change the operational mode depending on the influx from the formation. To date the flow rates are measured periodically (once or twice a day), which is not enough. The monitoring and diagnostics system enables to receive real-time pressure data from the submersible transducer and use this information for automatic calculation of "instantaneous" flow rate. For this purpose the Company carries out pilot projects to try out the submersible telemetry systems (Russian-made) with additional transducers that record pressure and fluid temperature at the submersible pump discharge end and their transmittal to the external devices. Russian manufacturers of submersible telemetry are taking initial steps in producing telemetry systems with additional transducers. Also, in field development the oil companies face the problem of solids flow-back from the wells. The use of ultrasonic transducer to evaluate amounts of solids flown back from the well and their type is the most advanced practice. Ultrasonic transducer for solids detection has the following technological advantage: it enables to ensure optimal rate for the complex wells stock by means of data-based control and prompt real-time response to changes. In this paper the authors described application of such systems.
Terrain or severe slugging has been observed operationally in a 5-mile long subsea oil tie-back when certain wells or combination of wells are flowed back to the platform through the test line. The flowlines have a downward incline to the base of the riser that enhances terrain or severe slugging. Under operating conditions with slugging, the tuned flow management tool failed to predict any slugging. Additionally, according to multiphase flow analysis with a commercial transient simulator during design studies, slugging was not predicted except for significantly lower flowrates and higher water cuts. Recent rigorous modelling highlighted significant differences to the resulted slugging predictions depending on the modelling approach and different versions of the tested simulator, OLGA®. Also the commercial transient simulator LedaFlow® was tested yielding similar results to OLGA® with same input parameters. Some slugging mitigation methods shown through modelling to mitigate slugging have been tested in the field without success. While the more rigorous modelling achieved better agreement with operating data, still poor accuracy was achieved. The inability to properly capture multiphase flow characteristics during the design phase of the project has led to an under-designed system and significant process upsets. 1 INTRODUCTION The accurate prediction of multiphase flow phenomena has been the topic of research for many years. Even though steady state conditions can usually be predicted with good accuracy, significant efforts are still being expended to model transient flow phenomena, such as various slug types and transient operating conditions, such as shut-downs, blowdowns, restarts, and ramp-ups. Accurate steady state and transient flow assurance analyses during early design phases are paramount to the further engineering of a subsea oil or gas project. Slugging inherently creates significant issues in the topsides process train due to large fluctuations in operating conditions.
Abstract Exploration and Production companies operating in Coal Seam Gas (CSG) consistently face challenges in regards to efficient well monitoring and operations. CSG wells are completed with artificial lift and have fluid flow in both tubing and annulus. The water is being produced with the help of artificial lift through tubing and gas is produced through annulus. Well production depends on artificial lift performance and flow profile within the tubing and fluid level in annulus. The well modelling technique requires a common nodal solution from tubing and annulus which requires an iterative procedure to suggest optimum operating parameters and predicts rates for various scenarios. CSG wells have low gas rates which induce slugging in the annulus and hence adversely affect the well performance. The unwanted down hole pressure variation leads to reduction in lift efficiency both in tubing and annulus. The operating condition of artificial lift requires optimisation to operate the well at maximum production potential. The fluctuation in liquid rates from wells needs to be minimised for process stabilisation and hence reduction in back pressure effects on other wells in surface network. The main objective of the exercise presented in this paper is to model the flow path inside tubing and annulus for an artificially lifted CSG well. There is currently a gap in the industry on how such wells should be modelled since the water & gas are separated down hole and they follow different flow paths. A flowing well has a common down hole pressure at different surface flowing tubing head pressure and flowing casing pressure. This project involves development of a software tool on the basis of industry research which can execute performance analysis in CSG wells. In addition, the scope of the project includes identifying basic guidelines for operating a CSG well. To achieve this objective all issues related with CSG well operation were collectively analysed and scope of work was drawn. The requirement of performance analysis tool for unconventional wells was acknowledged and the workflow for optimum well operation was proposed with available software applications. An Excel based application running on visual basic code was created which can communicate with a multiphase pressure calculator and perform system analysis for CSG wells. The proposed tool was developed and validated on real field data from BG Group. This paper covers the operating issues, proposed workflow for performance analysis for CSG wells, development stages of the tool, its application on real field data, validation with field measurements and limitation associated with developed workflow. This thesis also covers the main aspects considered to monitor performance of CSG wells; the effect of surface and downhole parameters on well performance and how these concepts and diagnosis can help to achieve production targets in CSG field.
- North America > United States (1.00)
- North America > Canada > Alberta (0.28)
Abstract Declining reservoir pressure and rate in the Jonah field has led to the common problem of liquid loading. As fluids accumulate the downhole pressure increases which decreases the available drawdown that allows fluids to flow into a wellbore. Jonah wells are completed in the 2000 - 3500-ft thick Lance Formation, using 8-16 hydraulic fracturing stages. With initial end of tubing (EOT) depths set above the top perforation for most wells, this left approximately 1500-3000 feet (gross pay) of perforations below the EOT. With lifting velocities significantly greater in larger diameter casing than tubing, a liquid column was developing below the EOT and engineering and operational attention was needed to improve field performance. Improving on the operational efficiency involved the implementation of recommended actions from a cross-functional well by well review group that received input and support from all Jonah asset members. The approach focused on how to improve liquid removal and optimize gas production from wells identified as liquid-loaded. In addition to installing plunger lift systems and injecting soaps, in 2008 a program was started to lower production tubing in wells by approximately 50-70% into perforations; the purpose was to reduce the column of fluid in the wellbore by helping more efficiently unload fluids using the reduced critical flow rate in the tubing and allowing plungers deeper access to the column of liquid covering the perforated interval. This paper discusses the results of lowering the EOT of over 100 gas producing wells in the Jonah field. The wells showed an average sustained uplift of approximately 105 mcfd, with undiscounted payout of less than 12 months. In addition, on wells that have had the tubing lowered, their decline curves appear to flatten out, offsetting anticipated double digit decline. Practical methods of selecting candidate wells and the new EOT are presented and discussed.
- North America > United States > Wyoming > Green River Basin > Jonah Field (0.99)
- North America > United States > Utah > Green River Basin (0.99)
Abstract: Rock grouting is performed to decrease the hydraulic conductivity around underground structures, such as tunnels and caverns. Cement grouts are often used and pumped into joint and fractures of the rock formation. Piston type pumps are mostly used for high pressure rock grouting. A pulsation ef-fect is inevitable when using this type of pump due to the movement of the piston. The effect of this pulsation on rock grouting is yet to be known but believed to be benefi-cial for the penetration of the grout. Current flow meters used in the field are not accu-rate enough to determine the fluctuation of the flow rate when it is less than 1 l/min. The feasibility of this method was successfully investigated for the direct in-line determination of the rheological properties of micro cement based grouts under field conditions (Rahman & Håkansson, 2011). Subse-quently, it was also found that this method can be very efficient to measure the fluctu-ation of the flow rate for different types of pumps. From a grouting point of view the UVP+PD method can be used to synchronize the pressure and flow of a piston type pump by measuring the pulsation effect. Conse-quently it can be used as a tool for the efficiency and quality control of different types of pumps. 1 INTRODUCTION The principle of rock grouting remains the same for last few decades and for large tunneling projects a mobile grouting plant is often used. It consists of an agitator, mix-er and grouting pump. The pump is used to take the grout from the agitator to the boreholes through a line of hoses. Grouting pumps can be divided into two groups based on the assemblation of the valve in the pump (Houlsby, 1990). The valve results in pulsation of the flow.
Utilizing Production Logging in a Complex Completion to Enhance Productivity through Comprehensive Production Profiling, Workover Planning, and Recompletion
Gupta, Shilpi (Schlumberger) | Sinha, Ravi (Schlumberger) | Kumar, Ajit (Schlumberger) | Pandey, Arun (Schlumberger) | Ogra, Konark (Schlumberger) | Verma, Vibhor (Schlumberger) | Bisht, P.. (ONGCL) | Hinge, P. P. (ONGCL)
Abstract Production logging (PL) has long been in use in the industry for evaluating the well performance for making strategic decisions. However, understanding the production profiles is challenging in complicated flow regimes and complex wellbore completions. To increase productivity in underperforming sick wells, electrical submersible pumps (ESPs) are generally effective options if planned and installed judiciously. This unique case study validates the application of production logging in planning and executing workover operations and by diagnosing the issues for suboptimal production performance of an ESP completed well. Located in XYZ field of Mumbai offshore in India, Well G has been in production since October 2006, predominantly producing at the rate of 900 barrels of oil per day (BOPD) with 10% water cut (WC). After producing for 2 years, well production declined significantly to 600 BOPD. PL data were used efficiently to increase productivity at three different stages during the life of the well. In the first stage, PL played a key role in mapping the zonal production profile. On the basis of these data, an acid job was suggested, which increased production by 300 BOPD. In the second stage, when the production rate again declined to 600 BOPD within a year, PL played a key role in defining perforation and re-perforation strategy by identifying the silent zones and helping to plan ESP installation when the well was incapable of lifting fluids to surface. This led to an increase of only 50 BOPD as compared to the expected increase of 600 BOPD. During the third stage, PL combined with a Y-tool was instrumental in diagnosing a mismatch between ESP design capacity and reduced reservoir deliverability, which was the key reason for the unexpected underproduction. On the basis of the diagnosis, an acid job was suggested to increase well deliverability. Following the acid job, production increased by almost 75% to 1034 BOPD without changing and damaging the ESP. This case study is of interest to plan workover operations and to diagnose production problems using PL to optimize production in ESP completed wells with changing reservoir productivity.
- Africa (0.94)
- North America > United States > Texas (0.47)
- Asia > India > Maharashtra > Mumbai (0.25)
- Well Completion > Completion Installation and Operations > Perforating (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Well performance, inflow performance (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring > Production logging (1.00)
- Production and Well Operations > Artificial Lift Systems > Electric submersible pumps (1.00)
Abstract One of the current largest oil increments in the world in Saudi Arabia is undergoing field development. The southern part of the field traverses the Arabian Gulf Sea. The Production Engineering team crossed major hurdles in the development of this field with Causeways construction on artificial islands over drill sites to assess well sites. Flowback options on wells in these drill sites to unload drilling fluids presented key challenges. The flowback objectives included well cleanup, stimulation, production logging, and extended well tests for reservoir characterization requirements. Flowback would also allow conducting electric submersible pumps (ESP) spin tests prior to ESPs installation. A smokeless flaring option considered the heavy crude's characteristics with relatively high H2S content, possible emulsions from intermixing with completion fluids, interwell spacing limitations, and the sensitive nature of the nearby challenging marine environment. The choices were between using a conventional flare system and modifying the proposed layout to optimize the project's objectives while respecting the constraints imposed by a sensitive aquatic environment, highly sour crude, space limitations, and work conditions or implementing pre-existing conventional practices with the attendant risks of compromising health, safety, and environment. The authors examine the processes leading to the implementation of a smokeless and an environmentally friendly flowback option. The discussion includes the modifications made to the burner system, and H2S removal from the gas and oil phases. Also a new methodology is presented that fully controlled oil and gas flow to the burner to mitigate the risk of burner flameout for the highest burning efficiency, minimizing spills, and enhancing safe operation. The authors examine the pros and cons of other welltest options such as to re-inject produced fluids into the same reservoir, different reservoirs, or injection into water injectors. Key significant technical contributions include the presentation of several practical measures to avoid oil spills, and to guarantee ambient air quality. The welltest layout included several automation systems or the elimination of human interventionto deliver safely the project's objectives.
- Europe > Norway > North Sea > Central North Sea > Central Graben > PL 018 > Block 2/4 > Greater Ekofisk Field > Ekofisk Field > Tor Formation (0.99)
- Europe > Norway > North Sea > Central North Sea > Central Graben > PL 018 > Block 2/4 > Greater Ekofisk Field > Ekofisk Field > Ekofisk Formation (0.99)