Objectives/Scope Generally, tight reservoirs require hydraulic fracturing to enhance and sustain hydrocarbon production. However, fracturing requires frac string with bigger Internal Diameter (ID) to minimize frictional losses during hydraulic fracturing operation. This string ID may not be suitable to provide optimum Vertical Lift Performance (VLP) during production phase, particularly in oil wells. Therefore, it is required to replace the frac string with production string of smaller ID. Occasionally, artificial lift also becomes essential to overcome VLP issues in future due to progressive water production and declining reservoir pressure. Methods, Procedures, Process Completion replacement often causes reservoir damage due to killing operation, which can be removed in conventional carbonate reservoirs by matrix stimulation. However, formation damage removal is difficult in hydraulically fractured tight carbonate and sandstone reservoirs. Preventive measures become essential to avoid productivity impairment particularly in hydraulically fractured reservoirs. Different preventative options are proposed and reviewed to isolate reservoir with their advantages and disadvantages. After comprehensive studies and risk assessments, an innovative modification in the completion plan was introduced and finalized. This plan includes production string with Electrical Submersible Pump (ESP) to improve VLP. This completion provides full accessibility intervention job, which may be required for reservoir monitoring and surveillance in future. Results, Observations, Conclusions A comprehensive production test is performed to evaluate and compare the testing results of pre and post workover. Testing results show there is no impairment in productivity of the reservoir, which is avoided in workover process by isolating reservoir section. This paper summarizes the completion design process, selection criteria, challenges, and lessons learnt during design and execution phases. This technique will provide the guidelines for installation of the Production string/ESP in hydraulically fractured reservoir without productivity impairment. Novel/Additive Information With modified design, the reservoir is isolated from wellbore and completion with ESP is run successfully without killing reservoir section. Underbalance conditions are achieved prior to establishing communication between reservoir and wellbore.
Water injection is seen as one of the key field development strategies to achieve the mandated production target as it will maintain reservoir pressure as well as improve sweep efficiency and increase field recovery factor. In current practices water supply wells workovers are planned after Electrical Submersible Pumps (ESP) are failed by adopting run to fail approach. This lead to decrease in well availability and increase in down time which impacts water injection cluster capacity in giant matured onshore oil field. The objective of this solution is to early detect the failures for ESP wells using Machine Learning (ML), by demonstrating the feasibility of this approach and verifying that the concept has practical potential, the tool can be used to reduce deferment and increase well availability either by extending time-to-failure or better planning and scheduling the workovers. In this solution, Predictive Analytics model was developed based on Algorithms using field sensor data, and well failure history to predict ESP well failure probability. Due to the limited available ESP real time data, it would be a challenge to have an accurate model. The downhole and temperature data is not available in these ESP wells. Hence, we have adopted unsupervised classification approach combined with statistical calculations such as MTBF based on failure history. The solution provides a probability of ESP failures based on the anomalies (anomaly severity) detected from unsupervised machine learning model (individual cluster based), MTBF & number of starts. The probability is normalized based weight-based approach. Additional criteria can be added and considered in the future to fine tune the model and predictions. The approach has successfully evaluated on 34 water injection clusters in this giant field. The model is able to predict 77% of failures historical failures successfully. The limitations in ESP down-hole data availability and real time quality issues impacted model accuracy. The solution has been successfully deployed in real time mode and able to predict failures 90 to 120 days before failures. This has resulted increase in well availability by 10% and increased water injection system capacity. This machine learning based approach has been extended to all water injection clusters and also capitalized in other fields to increase well availability and grow capacity with the increasing demand for water injection to sustain and grow production volumes
More than 155 Electrical Submersible Pumps (ESP) are installed in water supply wells in one of United Arab Emirates – Abu Dhabi Onshore area fields (ADCO). The water supply wells producing wells are characterized by low reservoir pressures, high production rates, low levels of H2S and toxic gas. The produced reservoir formations mainly consist of soft limestone and with variable porosity. This paper will highlight the major techniques used to boost ESP system run life and enhance reliability in onshore application. These techniques are as follow: Equipment selection - Redesigning equipment to adapt to reservoir parameters and productionUpgrading of ESP equipment, accessories, seals and consumables to withstand reservoir pressure and fluid propertiesOperation Practice Developing guidelines to enhance operation practice and test equipment integrity in workshopWell condition –Monitor the well condition and advice field production and operation team to schedule the well for periodic clean out and stimulation to enhance the production The above technical enhancements made were to improve ESP performance in scale forming and corrosive environments. The focus will be on case histories to discuss what was implemented and the methodologies that were used to overcome specific challenges encountered with the use of ESPs. The analyses will overview ESP failures from the period 2011 to 2016. These proposed solutions helped the in improving overall ESP system run life and reliability from 459 days (year of 2013) to 878 run days (year of 2016). It also helped the in reducing the MTBF (Mean to before failure) from 581 days (year of 2013) to 1079 run days (year of 2016). Additionally it reduced the OPEX by 35%, ESP failures in ESP water supply wells from 35 failures (2013) to 18 failures (2016), well down time, and potential HSE risk related to well intervention and work overs.(fig 01) Figure 1No. of ESP failures in water supply wells
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