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In the normal life of an oil or gas well, sometimes the well produce water in conjunction with the desired hydrocarbons. In the initial stage of life of the wells, the wells have sufficient energy to carry undesired water through the well bore and out of well to the surface. With the passage of time, the reservoir pressure depletes, and it leads to a decrease in well production. When this occurs the flowing pressure decrease and have an adverse effect on the well to carry and remove the undesired water being produced by the well. When the well can't carry said water out of the well bore it builds up in the production tubing and the well shuts off flow to the surface. Soap sticks are deployed on the wells to generate foam and to overcome the liquid loading, thereby reducing the surface tension and lowering the fluid density. The customer was experiencing liquid loading in many of its older gas wells which has a considerable impact on production targets. The liquid loading was a major challenge for the customer. The customer was using coil tubing and nitrogen kick off to offload the liquid loaded wells. The cost associated with nitrogen kick off was vey high. The customer was looking for a cost-effective solution to offload liquid loaded wells. This paper describes the application of Soap Sticks on liquid loaded wells and demonstrates that the use of Soap Sticks is cost effective and sustainable alternative to unloading by coil tubing. Initially, two liquid loaded wells were selected for Soap Sticks treatment. The data for two wells, Well X-1 and Well X-2 was used for analysis and to prepare best treatment plan. The Well X-1 was a deviated well with 4-1/2-inch single string completion. The well was producing 4944Mscf/d and 39 bbl/day liquids. The well was loaded up with water and was unable to deliver the desired production rates. As per the analysis, the Soap sticks were launched, and the well was unloaded successfully. The Well X-2 located in the same field and was a vertical well with 4-1/2" single string completion. Based on historical data, this well was producing around 4310 Mscf/day. The production from this well dropped to 1704Mscf/day and it was kept dropping continusly. Prior to the field trial the liquid column height was determined, and the required number of Soap Sticks was calculated for the candidate well. Commencing the field trial, Soap Sticks were dropped in the well and wellhead pressure was building up. After several hours of pressure build up the well was opened whilst monitoring the flow rate and wellhead pressure.

One of the key aspects of production optimization and monitoring towards digital transformation requirements is to have reliable and accurate data / measurement. This submission demonstrates how the smart technologies for direct wellhead measurement using Coriolis meter in gas field significantly help asset in production monitoring and Opex optimization while accurately regulating the field rates. The use of the smart technology in direct well head measurement provided real time insight into well production, with continuous and reliable quality data on production enabling Reservoir and Production Engineers to take timely decisions to optimize production, improve mass balance, better reservoir management, and reduce operating cost. The technology also had built in advanced diagnostics and connectivity features paving way for digitalization of oil fields and remote online access of data. The high operating range and flexibility in switching between wells offered ease of adaptability, reduced engineering, and commissioning costs as well as reduced maintenance and inventory requirement in mass implementation. Prior to scale-up, a trial / pilot was conducted in collaboration between ADNOC TC, Bab site Production & Instrumentation team and vendor for the technology over a period of 2 months. First, Multiple wells were selected from different operating envelop aiming different reservoirs. Then, the technology was tested by installing the Wet-Gas Coriolis meter in series with a portable well testing package provider. The measurement of the well tests from both techniques were compared. This is to evaluate the performance of the technology in having a reliable data compared with the current periodic measurement. Finally, evaluation report was produced to show the challenges, data verification and validation, then plan for wide field implementation. The technology provides real time insight and continuous monitoring of well production and its profile resulting in better production management. With direct real time well head measurement, significant CAPEX and OPEX savings can be achieved in additional to optimizing production with the use of digital transformation capable technology. Additionally, Support the asset digital and back allocation initiatives. Significant optimization on periodic portable separator well testing requirement. Permanent installation of the Wet Gas Coriolis meter on all wells will empower continuous production monitoring capabilities by increasing the availability of the real time multivariable well data. Continuous data and actionable insights will be used to identify new development opportunity to maximize recovery. Advanced diagnostics capabilities enable predictive maintenance and reducing operating costs. Improved Reservoir and well modeling and production management. No intervention cost required and enhanced HSE measures. Well behaviors change over time and can't be accurately predicted specially with the depleted wells. The current method of relying on intermittent well testing data is insufficient, expensive, labor intensive and increases safety risk. Continuous real time insight into production is essential in optimizing production, improving mass balance, better reservoir management and reducing optimizing cost. The implantation in 60 wells have a value proposition of $5.98 M over a period of 5 years.

With a vast reservoir with a complex and dynamic system production system containing more than 300 wells, both producers and injectors, keeping track of the field operational activity like Reservoir Monitoring Plan (RMP) jobs can lead to sub-utilization, confusion, lack of efficiency, and loss of time. This paper describes an integrated and collaborated method that supports monitoring and execution of field activity tasks utilizing the integrated production optimization platform and the business intelligence tools. Reservoir monitoring planning (RMP) is one of the critical workflows used to ensure the smooth execution of tasks at the required time. This enables the user to plan future tasks based on the reservoir behavior and have a quick comparison between actual and planned tasks. The process starts with inputting the planned tasks into the integrated system, categorizing the tasks based on types, and assigning the executors. The system sends reminders/notifications of the planned task approaching the task due date to all the stakeholders. It also provides an automated direct summary/bird's eye view utilizing the business intelligence tool. Using an integrated asset operation model (IAOM) solution in a digital platform, this planning and monitoring workflow has enabled the users to establish a standardized and unified central repository for the tasks to ensure the single source of truth. With the help of this advanced workflow, inter-departmental communication gaps have been reduced tremendously, thus enabling better execution, analysis, gaps, or bottleneck identification. The automated summary dashboard contains the comparison of the actual status of tasks versus planned tasks. This helps in optimal facility utilization based on dynamic RMP monitoring. Additionally, the integrated solution for planner, performer & approver enabled the users to prioritize the activity based on bottlenecks faced during the past months and reduce the times used to update the monitoring Excel sheets. This outlining process provides a standardized approach across the assets, leading to improved tracking efficiency, minimizing the time spent on manual monitoring, planning, and receiving automatic reminders to avoid delay in the planned tasks, which assisted the users in focusing on production optimization and solving different bottlenecks. This reservoir monitoring and planning approach aligns with the overall corporate strategy of using an integrated asset operation Model (IAOM) for providing end users with tremendous opportunities related to system optimization. This also supports the users’ drive to switch the approach from individual people oriented to standardized process oriented. This approach supports standardization of the work process across the organization and a minimum of $ 700K value proposition from manpower time saving over five years.

This paper describes accurate, efficient, and time-saving methodology for achieving the Business target by determining well allowable using advanced, integrated, and automated work-process for a gas condensate field with more than 350 (producing and injecting) well strings from a multi-layered reservoir, having varied reservoir characteristics. This paper will also illustrate challenges and enhancement opportunities toward full smart field applications. Integrated asset operation modeling (IAOM) within a digital framework provides automation to the engineering and analytical approach of allowable rate calculations. The approach comprises 3 step calculation process to determine the Well targets/allowable. Firstly, using the shareholder/reservoir management guideline along with calibrated well models for calculating the well's technical rate. Secondly, calculation of the well and reservoir available/potential rate using the well technical rates, reservoir target, and an inbuilt analytical solver. Thirdly, determination of the well allowable rate by conjugation of various well production components, including wellbore dynamics (Inflow performance and Well performance) and surface constraints. In a digital platform, this automated "Well allowable" workflow has enabled engineers and operators to determine the true potential of wells and reservoirs, thus overcoming potential challenges of computational time saving and identification of cost improvement opportunities. The use of the automated workflow has reduced the time to compute well allowable rates by more than 90% for a gas condensate field with more than 350 (producing and injecting) strings. Implementing this workflow prevented engineers from performing a tedious manual calculation on a well-by-well basis, allowing engineers to focus on engineering and analytical problems. Additionally, this efficient engineering approach provided the user with key information associated with the well's performance under various guideline indexes such as well available/potential rates, well technical rate, reservoir available rate, and rate to maintain drawdown/ minimum Bottom-hole Pressure. This advanced workflow computes the rate that can be delivered from each well corresponding to each guideline and constraint, thereby providing key inputs to various business objective scenarios for production efficiency improvement. Post-implementation, some challenges turned into opportunities to ensure the full and smooth implementation of the generated production scenarios adhering to the gas demand fluctuation. The accuracy and robustness of advanced and automated workflow of setting well allowable /production scenarios empower users to establish well performance and deliverability with a solid engineering analysis base, thereby providing key opportunities for saving cost computational time and assuring short-term production mandate deliverables. This approach supports standardization of the work process across the organization and a minimum of $ 2.8M value proposition from manpower time saving over 5 years.