Haider, Bader Y.A. (Kuwait Oil Company) | Rachapudi, Rama Rao Venkata Subba (Kuwait Oil Company) | Al-Yahya, Mohammad (Kuwait Oil Company) | Al-Mutairi, Talal (Kuwait Oil Company) | Al Deyain, Khaled Waleed (Kuwait Oil Company)
Production from Artificially lifted (ESP) well depends on the performance of ESP and reservoir inflow. Realtime monitoring of ESP performance and reservoir productivity is essential for production optimization and this in turn will help in improving the ESP run life. Realtime Workflow was developed to track the ESP performance and well productivity using Realtime ESP sensor data. This workflow was automated by using real time data server and results were made available through Desk top application.
Realtime ESP performance information was used in regular well reviews to identify the problems with ESP performance, to investigate the opportunity for increasing the production. Further ESP real time data combined with well model analysis was used in addressing well problems.
This paper describes about the workflow design, automation and real field case implementation of optimization decisions. Ultimately, this workflow helped in extending the ESP run life and created a well performance monitoring system that eliminated the manual maintenance of the data .In Future, this workflow will be part of full field Digital oil field implementation.
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.
This paper describes the selection, field application and performance monitoring of jet pumps in the giant Mangala field situated in the Barmer basin in Rajasthan, India. The field contains more than a billion barrel of STOIIP (Stock Tank Oil Initially in Place) in high-quality reservoirs. The field was brought on production in August 2009 and is currently producing at a plateau of 150,000 bopd. Mangala field is characterized by multi-Darcy rocks with mix to oil wet characteristics. The oil is waxy and viscous, with wax appearance temperatures close to reservoir temperature.
Jet pump has been selected as the preferred artificial lift method for the deviated wells. The base development plan included hot water flooding; this makes water heated up to 85 °C available at the well pads as power fluid for jet pumping. In order to prevent exposure of carbon steel production casing to corrosive reservoir fluid, the jet pumping process involves pumping the power fluid down the annulus and taking returns through the tubing.
The results have indicated that the jet pumps are giving required drawdown, thereby restoring the liquid productivity of the wells. In addition to restoring well production, jet pumping has also been used as an effective and fast method for cleanup of deviated wells completed with sand screens. The real time monitoring of the jet pump parameters, using Digital Oil Field (DOF), has immensely helped in efficient monitoring the pump performance and reducing the response time in case of problems.
Jet pump application has helped in restoring the deliverability of wells at high water cut for such a viscous crude. Further analysis of the pump behavior will provide insight for efficiently operating these pumps which is critical for maximizing recovery from the field at higher water cuts.
This paper describes the selection, design, successful application and performance monitoring of Electrical Submersible pumps in the giant Mangala oil field and Thumbli water field situated in the Barmer basin in Rajasthan, India. Mangala oil field contains approximately 1.3 billion barrels of STOIIP in high-quality fluvial reservoirs. The field was brought on production in August 2009 and is currently producing at the plateau production rate of 150,000 bopd of which approximately 40% of the oil production is from the ESP oil wells.
To support the water requirement of Mangala and other satellite oil fields, Thumbli source water field was developed with 5 water production wells with up to 4 wells operating at a time. Each of these water wells is installed with 60,000 bwpd capacity pumps and the field is currently producing up to 225,000 bwpd to meet the water requirements of Mangala and other satellite fields.
The Mangala oil field is a multilayer, multi-Darcy reservoir, has waxy viscous crude with in-situ oil viscosity up to 22 cp and wax content in the range of 18 to 26%. The field was developed using hot water flood for pressure maintenance. Significant production challenges included unfavorable mobility ratio with early water cut and hence the early requirement of artificial lift to maintain the plateau production rate. The field has 12 horizontal producers and 100 deviated producers. ESP was selected as the artificial lift mode for the high rate horizontal producers while hot water jet pumping was selected as the artificial lift mode for low rate deviated oil wells. Each horizontal well is capable of producing up to 15,000 blpd and high rate ESPs were designed and installed to deliver the production requirement. Currently 8 of the 11 horizontal producers are on ESP lift and the remaining three wells are planned for ESP installation in the near future. Apart from two early ESP failures during installation, ESPs have had a good run life; the paper also describes lessons learnt from the infant mortalities.
The Thumbli water field, located ~20 km southeast of Mangala field has been developed to meet the water requirement of Mangala and other satellite fields. Thumbli water aquifer is a shallow water field which contains water of ~ 5000 ppm salinity with dissolved CO2, oxygen, chlorides and SRB. 5 high capacity water wells were drilled in Thumbli field to meet the huge water demand from Mangala for water injection in Mangala and satellite field injector wells, hot water circulation in oil production wells and associated water requirement for boilers etc. 1000 HP water well ESPs were designed to produce up to 60,000 bwpd from each well with installed water production capacity of up to 300,000 bwpd from Thumbli field.
After 1859, sucker rod pump was invented commercially by C. E. Drake1, it was used vast majority of wells throughout the world. Thus, it became an oil symbol which comes to mind first for people even who are not engaged in this industry. Although SRPs are installed in about 90% of oil wells in USA, half of wells, 110 are installed by SRP in Adiyaman. Oil and water production is 13,000-13,500 bbl/day and amount of oil is 3,000-3,500 bbl/day.
This study explained that effects of parameters, which are related to reservoir and design, to the mean time between failures (MTBF) of pumps. In this controlled test, MTBF is dependent variable and well parameters are independent variables such as pump diameter, water cut, pump depth, stroke per minute(SPM), salinity and flow rate. These independent variables are examined one by one and completely. All data are taken from 384 well operations in 77 wells and spanned 3.5 years.
Index Terms - Sucker Rod Pumps, SRP, Run Life, MTBF, Design Parameters, Well Parameters
A detailed study and extensive evaluation was done by Talisman Energy to select the best artificial lift solution for the Situche Field in Block 64, Peru. Gas lift, ESP and Hydraulic Lift were studied. However, a New Technology, ESTSP (Electric Submersible Twin Screw Pumps- Multiphase) was selected for these sour, deep and hot wells.
This paper is part of the Define Stage document of Talisman Energy's Project Delivery System (PDS) for Artificial Lift Completions at Block 64 in Peru. Although the project in Peru is being shut down it is recommended that ESTSP be used in other complicated onshore or offshore wells.
The deep, hot oil wells, in Block 64, located in the Amazon rainforest of Peru, are a difficult environment for artificial lift. See the map on Figure 1. The Situche Central oil field would be the initial field development in Block 64.
The main goal for Artificial Lift in Block 64 is to provide a high rate lift system that is efficient, the least complicated and robust enough to survive severe downhole conditions at the Situche field. Run life, from initial pump installation, would be a minimum 2 ½ years, with no early time failures. Such a lift system would be safer (less rig time for pump repairs and less equipment handling and transport) and have the least impact on the environment.
A review of available information suggests that an ESTSP (electric submersible twin screw pump) with a PMM (permanent magnet motor) on a retrievable packer (new wells) would meet the above goals. Before deployment, this pumpset and ancillary equipment, would undergo a 3 month endurance test in a hot loop designed to simulate downhole conditions at the Situche Central Field.
This document shows the development process, information and analysis that would lead to the design, build, bench testing and deployment of a robust downhole electric pump system. These operations would occur during the execute stage of the Situche Field development. Also included is a description of the associated completion equipment required for the HPHT pump application such as power cable penetrators, a high temperature retrievable packer and high temperature gauges required for pump control.
Many researches had been carried out on the water jet pumps during the last few decades, and discussed the effect of changing the pump geometric parameters on its performance. Some other researches investigated pump performance with Two-phase (liquid-gas) and (liquid-solid) flow. In spite of the several researches, which investigated the case of liquid-liquid flow (almost as water-water), neither of them did have examined the case in which the secondary flow liquid differs from the power flow liquid in density and viscosity, which is the main objective of this paper. The subject is treated experimentally on a special test rig, with the primary fluid jet water and the secondary fluid of different types of oils. Performance of the jet pump and static wall pressure inside the mixing chamber, were measured as a function of the mixture Reynolds number. A one-dimensional analysis is also carried out, taking into account the difference of the viscosity and density of the two liquids (each primary and secondary fluids).
One-Dimensional Equations for the Jet Pump Performance
The one-dimensional flow assumptions are:-
1- Streams are one-dimensional at the entrance and exit of the mixing chamber.
2- Mixing is completed in the mixing chamber area.
3- Spacing between the nozzle exit and inlet of mixing chamber is zero, which is attainable due to the small nozzle diameter, relative to the large diameter of the mixing chamber. Momentum and continuity equations  were applied to different sections of the jet pump, namely the suction, inlet and outlet of the mixing chamber and the outlet of the diffuser. From this, the relationships between M, N & h and the performance of the jet pump were determined.
For more than 60 years, internal plastic coatings have been used for corrosion protection on tubing, casing, line pipe and drill pipe. One of the historic concerns with the use of internal plastic coating is the threat of mechanical damage and subsequent corrosion cell generation. Through the earlier years of usage of internal plastic coatings, applicators relied solely on enhanced surface preparation and adhesion to ensure minimal exposure of the steel substrate if damage were to occur. Even with this minimization, the potential for corrosion was still a concern for some. Due to this, a focus on developing internal coatings that offered higher degrees of abrasion resistance was initiated. At this time, several materials have been developed that offer abrasion resistances up to twenty times greater than what had previously been seen. These abrasion resistant materials allow internal coatings to be used in applications that were previously filled with alloys and GRE liners. These applications include: production/injection wells that rely on frequent mechanical intervention, rod pumping wells, completion string systems and environments containing high amounts of entrained solids. This paper outlines the development of these products including the different chemistries used and their abrasion resistance, impact, laboratory evaluation of their abrasion resistance and initial case histories of applications where internal coatings have historically been excluded.
By creating a common view on field operation data, harmonizing the language within a site and from site to site, it becomes possible to work from different locations towards common objectives, ensuring the same understanding of "what goes on" on site. This provides an opportunity for rethinking competences, roles and distribution of responsibilities within the organization.
Total has developed a methodology to build such a view, based on a "Common asset model" and a "Field Monitor Platform".
The "Common Asset Model" is a Rosetta Stone for field operations data; it contains a description of the field equipment that is comprehensible to engineers in all disciplines contributing to field performance management. The naming of equipment, the attached information, as well as the associated semantic metadata offer a clear vocabulary shared by everybody in the field. This ensures that data is used in a consistent and appropriate manner, according with its nature, its actual source, its time granularity, the process that has built it...
The "Field Monitor Platform" provides a unique entry point for end-user applications to access all field operation data actually stored in the multi-disciplinary IT systems. End-user applications could be monitoring tools, calculations, event handling or simulation tools. The system relies on virtual integration as it only holds pointers to data within its official repository and delivers it directly from the original source.
The Field Monitor Platform has been industrialized for use in Total fields operations with a first deployment in the Gulf of Guinea.
The main results of this effort are:
The critical gas velocity and flow rate for unloading liquids from a gas well has been the subject of much interest, especially in old gas-producing fields with declining reservoir pressures. For low-pressure gas wells, Turner's model (also called Coleman's model) is judged as more suitable for predicting liquid loading in gas wells. However, field practice proves that there are still a number of low-pressure gas wells producing without loadup when the production rate is lower than Turner's minimum production rate.
On the basis of experimental results, a new approach for calculating the critical gas-flow rate is introduced in this paper, which adopts Li's basic concepts, while taking into account the impact of the changes of gas-lifting efficiency caused by the rollover of droplets in the process of rising. A dimensionless parameter, loss factor S, is introduced in the new model to characterize the extent of the loss of gas energy.
Well data from Coleman's paper (Coleman et al. 1991) were used in this paper for validation of the new model. The predicted results from the new model are better than those from Li's model, and even better than Turner's model. The new model is simple and can be evaluated at the wellhead when the pressure is less than 500 psia and the liquid/gas ratios range from 1 to 130 bbl/MMscf, which is suggested by Turner et al. (1969) to ensure a mist flow in gas wells.