bluuebunny/crossref_metadata_2025 huggingface dataset:
Sulfur Deposition Phenomena in Gas Systems and Lessons Learnt
Authors: Gouhar Hatem Hamed , Ekaabi Abdulla Ahmed , Andru Prabhakar Reddy , Al Teneiji Bader Abdulla
Published: October 2022

This study is aiming to conclude the root cause of elemental sulfur formation in the Gas handling facilities for an Oil field development facilities. The study focuses on supporting the concluded root cause by actual field trials. Practical short-term, midterm and long term solutions were studied and recommended including an optimization strategy to maximize utilization of existing facilities. The lessons learned for future projects were listed to overcome and manage the elemental sulfur formation issue.

It was suspected that the root cause is related to potential oxidation of H2S due to the oxygen ingress associated with the generated nitrogen in the recycled low pressure gases. The study findings were achieved using actual field trials by either increasing the purity of the nitrogen source or by flaring (i.e. not recovering) the low pressure gases and monitoring changes in the operating conditions and the tendency of elemental Sulfur deposition for different N2 Purity levels. Accordingly, the mitigation measures were studied, assessed and the required modifications to overcome the problem are recommended.

The first field trial was conducted considering flaring low pressure gases and increasing the nitrogen purity from 97 % to 99.8 %. The second field trial was conducted considering only increasing the nitrogen purity to 99.8% without flaring. For both field trials the tendency of Sulphur deposition was monitored in the Gas lift system and findings were recorded. The nitrogen purity was reduced gradually from 99.8 % to test implications on operation and note the nitrogen purity level at which Gas lift choke valves and Gas lift/ gas injection compressors are chocked by the elemental sulfur formation.

According to the results of the field trials, the H2S oxidation due to the oxygen levels in the nitrogen stream was confirmed as the root cause for the elemental sulfur formation. All the lessons learnt to be considered at different stages of any project were captured and summarized in a typical checklist for the design of similar facilities at each project stage.
De-Salting Train Transformers Retrofitting and Optimization Study to Achieve Flexibility and Efficiency in Saudi Aramco
Authors: Bajuaifer Hatem A. , Khan Ashiff , Mutairi Khaled N. , Kothawala Amir A.
Published: October 2022

This paper covers and evaluates a retrofit work for desalting trains grids in Saudi Aramco Khurais facility to accommodate water cut increases due to field maturity. The main objective of this retrofit work is to accommodate the increase in water cut (emulsified and free water) while enhancing the de-salting process with minimum modification scope and cost effective approach.

This Paper is intended to:

Presents the retrofit basis and compare old and new grids design. Presents the results of this optimization study along graphical representations. Highlights how this initiative increased the desalting trains efficiency and redundancy.

The basic concept of the retrofit work is to change the grids in electrostatic separation vessels from the conventional tapered configuration to straight configuration. The original configuration was tapered configuration that is intended to maximize separation and balance the load on all transformers however the limitations of this configuration is in case of one grid shorted all other transformers will be shorted. Despite the available transformers capacity, however as the water cut increases the chances of water carry-over increases as well as emulsions which results in multiple outages of de-salting trains. Straightening the grids will help avoiding total outages of the transformer, so in case of one grid shorted, other two grids will be running with a higher load which provides redundancy, reliability and guaranteeing the quality targets.

This modifications were evaluated from safety, process, electrical and cost life cycle point of view and assessed post retrofitting for 1 year against there pre-defined success majors that includes:

Outage hours of dehydrator and/ or de-salter (Target less than 5 hours per quarter). Demulsifer chemical consumptions (Target reduction by 10% or more annually) Quality specification (Target maintaining BS&W and Salts within crude specifications of 0.2% and 10 PTB respectively even in case of 1 or 2 transformers shorted.

This modifications succeeded in achieving the predefined targets in addition to a cost saving equivalent to US$ 120,000 due to demulsifer injection reductions (i.e Regular and emergency dosage).

Figure 1 shows the change in grids configurations before and after retrofit work
Using a Hybrid Off-Grid Semi-Fixed Solar System to Power a Water Pump in a Water Supply Well in Remote Areas
Authors: Ruheili Sharifa Mohammed Al , Mahrami Khansaa Hamed Al , Wardi Khalid Hamood Al , Hashmi Mohammed Marhoon Al , Al-Jaaidi Omar Salim
Published: October 2022

ARA Petroleum Exploration and Production Company has successfully installed a hybrid off-grid semi- fixed solar system to power an Electrical Submersible Pump (ESP) for a water supply well in Oman's remote area (Oil North Field). The system is designed to provide the power output of a 40 KW water ESP pump. The pump usually runs for 10 hrs/day. The well is used for supplying water for drilling activities and other operational requirements with an actual power of 30 KW.

The uniqueness of this system is its ability to power the ESP well directly without an over-headline (OHL) with a synchronizing system and an automated switchover to a diesel generator when required. Moreover, a real-time operation system that can be downloaded on a mobile application. In addition, a CCTV camera, and solar lighting are available in the location to control and monitor the performance of the solar system.

Utilizing solar systems in this project provides a cost saving on diesel consumption and reduces its associated CO2/GHG emissions. The system runs in the daytime on solar for 6 hours. The rest of the 4 hours is compensated with diesel. The anticipated cost saving on diesel consumption and CO2 emission reduction is around 60%. The success of this project will allow the technology to be replicated in many locations in remote areas.

In order, to support the ICV and develop SME companies, the project was awarded to a local SME company, and the learning from this installation was shared between the vendor and ARA E & P, as this system was the first of its kind implemented in Oman.
Field Water Management Using Inline Water Separation
Authors: White Ramsey James , Alghunaimi Fahd I , Aljuryyed Norah W
Published: October 2022

Increasing water-cuts is inevitable for mature oil fields in which water flooding is used to achieve higher recovery targets. As water rates increase, significant investments are required to debottleneck water handling facilities and pipelines. This paper summarizes a detailed assessment to find the benefits of implementing a separation process to improve water separation efficiency. Inline Water Separator is considered here to optimize capital expenditures, building on the experience of a field demonstration of the technology.

A prototype pilot plant was installed demonstrating an Inline Water Separator technology. Using a set of different inlet conditions. The technology was able to achieve +70-80% separation efficiency and deoiled the water to a maximum oil-in-water concentration of 35 ppm reaching lower than the accepted oil in water discharge criteria for reinjection (Zhang et all). Building on the success of the prototype, a suggested roadmap was studied to expand the testing of the technology at further harsher conditions with heavier crude grades and test alternative Inline Water Separation Technologies. A business case assessment was also conducted to determine the feasibility of the Inline Water Separator solution versus conventional water handling upgrades.

Alternative Inline Water Separator technologies were also looked at as modularly designed skids that are easily transportable. The skids can be installed at different locations such as remote well manifolds or immediately pre-inlet processing facility. A technical and economic assessment of Inline Water Separator was conducted. It was found to be an economically attractive alternative to implementing conventional extensive oil-water separation, crude oil desalting, water deoiling & injection and pipeline network upgrades. The benefit of IWS besides reduction in capital expenditures, enhanced oil-in-water and a reduced overall energy and chemical consumption also results in reduced operating expenditures. When IWS is installed at the well manifold the stud shows a that the water rate will be reduced in the trunkline downstream the inline water separator and therefore a reduce the backpressure on the well will accrue, which can potentially increase the oil rate. Another benefit that was found, this design will potentially enhance distribution of field water injection as separated water from the inline water separator can be rerouted to another desired location or flank.

The study of the Inline Water Separator technology portfolio expansion is highly recommended as a strategy to optimize capital expenditures to manage increasing produced water rates. The paper provides the alternative solutions, potential benefits and business case assessment to justify potential deployment.
Early Detection of Compressor Liquid Carryover Enhanced by Multiple Facilities Monitoring
Authors: Pezzola Mattia , Turconi Fabio , Gamboa Ortiz Alfredo , Beduschi Francesco , Mosca Alessandro
Published: October 2022

This work aims to present a methodology based on a proactive approach for the early detection of possible liquids carryover towards compressors installed in upstream process plants where the presence of heavy hydrocarbon inside gas stream is a recursive problem. Analyzing trough remote monitoring some parameters of the facilities that are upstream to the compressor and, simultaneously, some machine critical instrumentation that was selected through early detection algorithms, it is possible to develop real time synthetic indicators that warn the possibility of liquid ingestion.

An in-depth analysis of the plant and of the process lines and facilities that are upstream to the compressors, permits to identify the critical parameters to monitor, which unequivocally indicate a change in both physical conditions and gas composition.

This methodology has been applied to create tailor made synthetic indicators that have been implemented in operating sites, to highlight the upset in the process parameters that could have led to liquid carry over with consequent possible mechanical breakdowns. These indicators enhance the deep analysis of these phenomena, resulting in the development of tailored operative adjustment to be applied at the early stage of the liquid carryover occurrence. The combined monitoring both on the upstream facilities and on the on-board instrumentation of compressors allows to have an early detection of the liquid carryover events, giving time to the operators to understand the situation and act accordingly to avoid hazardous conditions.

The methodology innovative feature is the ability to monitor, by remote, a combination of critical parameters at "plant level", together with cross-check trough machine-learning algorithms of the relevant on-board instrumentation at "compressor level" to have a complete picture of the phenomena and prevent the compressors from unplanned damages due to liquid carryover.
Commingled Production, a New Era in Mature Fields. Lessons Learned and Practices in ESP Lifted Wells Achieved 29 % Incremental Production During Initial Implementation in Shaya Project
Authors: Villalobos Jorge Luis , Andagoya Carrillo Kevin Ismael , Quinzo Maria Elena , Orozco Andres , Enriquez Luis Carlos , Reyes Carlos , Gonzalez Patricio , Torres Richard
Published: October 2022

For many years, commingled production has not been considered as a valid alternative to produce mature fields; actually, oil regulations in many countries do not allow this technique. This was the case in Ecuador until 2021. In 2021, Ecuadorian regulations allowed commingled production to increase the oil recovery. The main objective of this project is to present the artificial lift expertise applied in and the initial results, best practices and lessons learned of the first 13 wells of a commingled production campaign in the Shaya Project; the project focused on electrical submersible pumps (ESPs) and their operation. The aim was to enable a local best practice that established the well potential in commingled production model. This required the ESP design to lift at and beyond the expected target production, which was accomplished by the design of a robust enough system to cover the wide range of uncertainties presented by the multilayered production and related problems with mature fields, including fines production, increased viscosity, and free gas into the pump. An additional requirement was to handle both the current and higher rates associated with future waterflooding. Thirteen wells were completed with a commingled strategy for close to 1 year. The analysis of input data together with the ESP design criteria for pump model selection and production regime has successfully achieved optimum results, producing without issues two producing zones at the same time without any additional downhole tools. This resulted in an average incremental production of 29% compared to the historical single zone production, 92% of the artificial lift systems are operating inside the optimum operating range with high efficiencies (above 50%), and 62 % of the wells achieved maximum drawdown with a flowing intake pressure of approximately 250 psia. Even though the pressure is below the average bubblepoint pressure, the downhole flowing conditions remain stable, and hence there is a constant flow regime at the surface.

The statistical projection of the mean time between failures shows a 100% survival probability for the already reached 384 days of operation, thus giving to the project the confidence that it is on trend to accomplish the expected target run life of the field. This project aims to share with the technical community what has been learned in the Shaya Project, after more than a year evaluating the commingled wells following a clear journey through all the phases: reservoir evaluation, inflow consideration, production analysis, uncertain scenarios, combined fluid properties, artificial lift selection best practices, the surveillance, and performance evaluation.
Maximizing Asset Value Through Unified Gas Injection and Gas Export Management Via Development and Adoption of Integrated Well and Process Automation
Authors: Mohd Sahak Muhammad Zakwan , Myo Thant Maung Maung , Tuan Mat Tengku Amansyah , Harun Zalina , Castillano Eugene , Bhave Abhijeet
Published: October 2022

In oilfield with significant gas production, either from high associated gas production or non-associated gas (NAG) wells, gas injection is often prioritized due to the aim of oil production sustainability compared to gas export, with only the remaining gas flow not taken by the injection wells is exported as sales gas. However, with gas emerging as a cleaner energy source as compared to oil and instability in oil price, higher gas demand is expected in the future. Due to this, flexibility in managing the allocation between gas injection and gas export would be an advantage, especially with the cyclical demand peak due to winter and summer seasons. A case study for optimization for a unified management and automation of the gas export and gas injection is presented in this paper, which includes the flexibility in prioritizing either utilization options and managing the impact of changes in injection gas supply accordingly via process control and automation.

With the adoption of new controllers, operator would now be able to choose which priority mode would be given considering subsurface injection and gas export requirements. For example, when priority is given to the gas injection as per current operating mode, only the remaining gas balance will be used for export. However, when gas export is prioritized, operator would have the option to set the minimum gas export flow that is required, and the control system will automatically control the allocation for sales and injection, including automatically calculating and assigning the injection gas flow to each injector wells when the resulting gas injection supply is changed as a result of gas export prioritization. With the automation exercise, the operator would not need to conduct the manual adjustment of choke valves opening to regulate the gas injection and gas export flow, rather only the usage mode prioritization and the desired flow setpoints for both cases are required. The scheme allows the operator to take advantage on the opportunity of prioritizing gas export or injection depending on prevailing market demand and operational requirement needs for maximizing the value from the field.
Waterflooding Communication Analysis at Well and Layer Levels Using Energy Balance and Capacitance Resistance Methods
Authors: Kshirsagar Atul , Yu Huijuan , Cranfield Colin Bertrand , Green Steve , Feng Gui
Published: October 2022

Reservoir surveillance and integration of geological and reservoir engineering studies are essential in optimising waterflooded oil field recovery. Maintaining calibration of dynamic models can be difficult as fields mature and watercuts increase, particularly where there is significant geological complexity. This can be even more challenging if the field is multi-layered with commingled production and injection. This paper describes how the energy method (EM) and capacitance resistance method (CRM) used for inter-well communication analysis were successfully employed to provide valuable insights in two such waterflood case studies and compares their results at well and layer levels.

In a preliminary step, classical waterflood surveillance and analytical techniques are combined with geological knowledge for a firm understanding of field performance. More detailed communication analysis is then performed to analyse inter-well and cross-fault communication.

In a first case study, the EM technique was used to examine waterflood effectiveness in six separate panels in the most faulted area of a mature, geologically highly complex oil field. In a second case study, both the EM and CRM techniques were used to assess and optimise the waterflood in the panel of another mature oil field.

The communication analyses provided a rapid route to understanding communication within complex, multi-layer fields using production data alone. In the first case study, results indicated significant communication between injectors and producers including across many of the faults separating reservoir compartments. Results identified areas of interest for infill drilling and possible workover targets. In the second case study, the combination of EM and CRM enhanced the overall understanding gained from the inter-well communication analysis.
Centrifugal Compressor Seal and Bearing Rubbing Due to a Destructive Repeatable Reverse Rotation
Authors: Ashour Mohammed , Shalabi Mustafa , Rengasamy S. G.
Published: October 2022

This case study is focused on the diagnostics of an abnormal event observed during each compressor train shutdown and led to a seal failure later through a detailed analysis of historical transient data collected using an online vibration online monitoring software during shutdown mode to identify the root cause of this abnormal behavior.

The unit consists of a centrifugal gas compressor (12440 RPM) driven by an induction electrical motor (3100 KW and 1790 RPM) through an increasing single stage double helical gearbox.

Machine train was running smoothly during steady state condition. Compressor bearings showed high vibration levels during each shutdown event close to alarm setpoints during last year, however no one took care as it was happening only during shutdown. The unit was compressing a hazardous gas, and any failure or leak could lead to a major safety incident.

Steady state data review showed good compressor rotor dynamics with acceptable vibration levels well below alarm set points, however during shutdown showed high vibration levels reaching alarm setpoints during shutdown. Review of the vibration and speed data through the online condition monitoring software showed symptoms of reverse rotation event repeating each shutdown after reaching zero speed.

After 3 month of operation and several shutdown events encountered, a gas leak took place from the compressor. During the internal inspection, severe rubbing marks found in the compressor seals and the rotor found damaged at these areas. Also, the compressor inboard bearing found totally damaged. Major overhaul took place changing the rotor and overhauling the compressor parts. The non-return valve installed on the discharge was dismantled and overhauled.

Compressor started up later and during the next shutdown the compressor bearings showed normal vibration behavior, and no reverse rotation events observed.
Unloading Liquid Loaded Wells- How Conventional Solutions Contribute to Sustainability Targets
Authors: Elabrashy Manar , Khan Zubair , Abbasi Haris Shakeel , Alsaeedi Ayesha , Al zeyoudi Mohammed , Grutters Marinus , Al Mheiri Eissa , Al Bairaq Ahmed , Ahmad Mubashir , Alsenaidi Shemaisa , Ahmad Zeeshan , Shaker Ashraf , Douglas Mahmood , Alblooshi Maryam , Siddiqui Muhammad , Albadi Mohamed Mubarak , Cristea Zaharia
Published: October 2022

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.
Production Excellence Program Enhances Operation Efficiency
Authors: Florez Fabian , Calderon Diego , Kartoatmodjo Gayatri , Fendt Andrew , Wilson Gregor
Published: October 2022

Many IOC and NOC organizations have and continue to be face with the challenge of establishing a corporate standard for measuring production performance across their producing assets. The difficulty with this challgenge comes from reporting localized production, managing production shortfalls, and identifying opportunities to increase production. These are three critical elements of production excellence or production performance programs.

This paper presents a solution for this challenge. This novel solution uses the choke model or limit diagram to integrate existing portions of the production performance framework; i. e., shortfall production management, opportunity identification workshops, and well potential calculations. The challenge is to duplicate these elements in a standard way across 12 active producing assets at different geographical locations, with diverse operating cultures, hydrocarbon types, contractual frameworks, and engineering criteria.

Within three years all assets were sharing the same basis for Production Excellence program (Px) with strict reporting discipling enabled by common corporate system. During the same period the overall production efficiency increase by 3% adding 1.1 MMBOE into the tanks.

In addition to the production baseline sustainability, other major benefits included the standardization of oil production loss classification and production opportunities identification workshop to keep the discipline of identifying production potential to reflect the everchanging field conditions.

This paper will present the integration of the Px program as the main endevoar to make it a portion of the operating culture and the proposed method to capture and share the performance gains. Additionally, a tremendous effort was made to build some of the elements directly into the production data management systems in the local operating assets to enable the corporate reporting system to read any source of data. These data are then used as a business intelligence application reporting accessible via smart and interactive dashboards.
Composite Materials for Cheaper Oil and Gas Production. Experience in Application.
Authors: Ablaev Anton , Ruban Konstantin , Zozulya Andrey , Kozlov Vladimir
Published: October 2022

The global composite market has been developing dynamically in recent years. The main goal of introducing composite materials as a replacement for metal - is to reduce the capital and operating costs of the enterprise. This paper describes Volga Gas's experience in developing four areas of composite materials application: well loops, tubing, petroleum product storage tanks, and process pipelines.

The main goal of this project was to replace metal well plumes with composite ones. As a composite material, the company "Volga Gas" suggested using fiberglass pipes, the installation of which is carried out in an easier way due to the absence of the need for welding operations and electrochemical protection. The last stage of this test is non-destructive testing. The technology of application of tubing is also offered (НКТ) made of composite materials. Despite the fact that the technology of launching composite tubing is similar to metal tubing, it has a number of advantages during further operation. It is important to note the technology of manufacturing tanks from composite materials. This technology is quite popular in remote fields, and the company "Volga Gas" successfully implements projects for the use of composite reservoirs in these conditions. The main advantage of replacing a metal tank with composite ones is a sharp reduction in the complexity of installation, and as a result, its terms. This paper also describes the technology of using pipes made of low-pressure poly-ethylene (GYL). These pipes can be widely used as process pipelines for corrosive liquids.
Virtual Tour (4.0) for Adnoc Offshore Assets
Authors: Mullick Partho , Almenhali Lateefa , AlAmry Mohamed , AlJaberi Manea
Published: October 2022

This abstract outlines the implementation of Virtual Tour (4.0) facilitating maintaining the dynamic changes to ADNOC OFFSHORE assets because of continuous ongoing Plant Modifications / Projects, thus resulting in the Engineering Drawings and 3D Models being overwhelmingly out of date, which impacts safety, operation and maintenance. Site visit becomes mandatory for decision making both by Company & Contractor personnel due to delay in availability of as-built drawings and 3D intelligent Models for a given facility.

Capitalizing on the advancement of Virtual Reality technology by creating an interactive Virtual Reality environment for all ADNOC Offshore operational sites is the need of the hour. Authorized and secured Business Users across ADNOC Offshore will have instantaneous visualization of offshore sites which optimizes the requirement for site visits meant for engineering, tendering activities and familiarization programs by more than 80%.

The output will be a user-friendly web portal easily deployed on the desktop or on a mobile device, the format following the spirit of "Street View" navigation that entails utilizing the latest 3D high-resolution laser scan technology output of point cloud & 360° high resolution photographs superimposed on each other.

A virtual tour environment/solutions aims to provide the below listed benefits, which is believed to be a future road map in terms of Return on Investment

➣ Site visits were reduced by almost 80%, so less overhead Logistic cost and direct man-days saving. ➣ Contractor's multiple site visits are avoided which is 2 to 4 Weeks Savings per Project/PMRs. ➣ Minimize Contract Variations due to site conditions with clear photos and sizing capabilities; variations any show stopper or risks are identified during the early stage of engineering. ➣ Provide visual support for Operations and HSE related induction/ training with the aid of 360° high resolution Images and Remote site measurement (up to ±3mm accuracy) ➣ Improve work preparation and facilitate the risk assessment process by identifying the equipment located in the area with Tag viewing feature. ➣ Visualize the event location and surroundings during emergency situations and drills. ➣ Facilitating visual inspection/coating inspection which reduces inspection & maintenance costs. ➣ Reduces dependency on the as-built layout drawings and intelligent 3D Model related to site conditions. ➣ Superimposing of 3D intelligent and non-intelligent model with laser scan true view point cloud. ➣ Facilitate up-to-date development of 3D e-Learning training modules. ➣ Facilitate to complement in the development of Digital Twin ➣ Less travelling to site will reduce Greenhouse emission and fuel consumption. ➣ Reducing the issuance of Permit to work.
Stochastic Optimization Workflow for Non-Uniform Coarsening of Simulation Grids and Location and Sequencing of Wells
Authors: Verma Santosh Kumar , Xu Yifei , He Shuai , Sanai Alireza
Published: October 2022

An adaptive differential evolution (DE) optimization algorithm and workflow are presented for non-uniform coarsening (NUC) of simulation grids resulting in smaller and faster models that maintain the key physics of the original model. The workflow presented here fully automates the grid generation process and results in a better NUC grid. The algorithm presented can handle discrete and continuous NUC grid generation parameters. We also use the DE optimization method for location and sequencing of wells.

A typical NUC grid generation process splits the reservoir into several regions: property preservation, near-well, far-well, etc. Several techniques for region splitting, e.g. time-of-flight (TOF), distance from wells, mixture of the two, etc. are used. The coarsening process has several types of parameters: continuous, binary, and integer. The resultant optimization problem is a mixed-integer nonlinear optimization problem which is solved using the modified adaptive differential evolution method.

Two methods are used to evaluate coarse grid quality. They are flow diagnostics, based on single-phase steady-state flow, and multiphase flow simulation. Well allocation factor differences computed from flow diagnostics and three phase production data differences computed from multiphase simulation are used in the objective function. These two objective functions are used in a two-stage optimization - in the first stage flow diagnostic differences drive the coarse grid generation process. A technique to prescreen NUC grids is presented for the second stage. It significantly reduced the time used in getting optimal NUC grids for all the cases that were studied. The NUC grid results clearly show the convergence of coarse grid results towards the fine grid results. Preserving fluid contacts in the coarse grid is found to be critical in getting an optimal NUC grid. A real field example with dozens of wells are presented that show the effectiveness of the adaptive differential evolution optimization workflow in achieving an optimal drilling schedule. Another set of examples demonstrate how the ability to move well locations within a user defined region helps us to further maximize the objective function.

The novelty of this adaptive differential evolution optimization workflow is the ability to automate the NUC grid parameter selection and the grid generation process; thus saving several days for a practicing engineer. Another novelty of the optimization algorithm is the ability to fully automate the process of scenario generation and simulation, thus saving time from manual exploration of the range of parameters.
Introducing Data-Driven Virtual Viscosity Measurements
Authors: Karpan Volodimir , Al Farsi Samya , Al Sulaimani Hanaa , Al Mahrouqi Dawood , Al Mjeni Rifaat , van Batenburg Diederik
Published: October 2022

Polymer-based chemical flooding is a mature enhanced oil recovery technology that has proven to result in significant incremental oil recovery that is both cost and GHG emission-competitive compared to the oil recovered by conventional waterflooding. For such chemical flooding projects, controlling the viscosity of injected polymer solution is critical because the polymer cost is one of the most significant cost elements in the project economics. The polymer viscosity is routinely measured in the laboratory using fluid samples taken manually at different sampling points (i.e., polymer preparation facilities, injecting lines, and well heads). However, in the case of large-scale projects, such viscosity monitoring becomes time-consuming and requires dedicated field staff. Moreover, the quality of laboratory-measured viscosity is questionable due to the potential viscosity degradation caused by the oxygen ingress or polymer shearing during sampling, storage, and measurement. The inline viscometers were introduced to improve the reliability of viscosity measurements and have a better quality of viscosity monitoring. Such viscometers are relatively simple devices readily available on the market from several vendors. However, the device comes at additional costs and requires modifications at the tie-in point (bypass line, drainage, and (sometimes) communication and power lines). On top of it, operational costs include regular maintenance that the inline viscometer requires to ensure good data quality.

This study introduces a data-driven Virtual Viscosity Meter (VVM) as a tool to augment the inline and laboratory viscosity measurements. Standard injector wells in a field are equipped with gauges that report injection rate, well/tubing head pressure, and temperature of the injected fluid. With such well data and viscosity measurements, calculating the viscosity becomes a machine learning regression problem. Training the machine learning regression methods on the actual inline and laboratory-measured polymer viscosity has demonstrated that VVM is a promising, high-accuracy solution with a low computational cost. The possibility of further implementing this approach to calculate the viscosity of an injected fluid was investigated using the data from several projects. Finally, the application of the VVM tool for viscosity monitoring and the limitations of VVM were discussed.
Record Setting Casing Run-In Speed Attributed to Significant Surge Reduction System Tailored for Deepwater HP/HT Operation in India
Authors: Gupta Shruti , Dange Mikhil , Missiaen Francois , Kumar Animesh
Published: October 2022

A major operator drilling in the Krishna-Godavari (KG) basin faced challenges attributed to tight tolerance and severe losses while running-in casing in deepwater conditions. The operator initially spent up to five days of rig time filling the casing conventionally and reducing running speeds to reach the planned depth.

To help mitigate severe losses and high surge pressure caused by tight tolerance in the wellbore, the operator had to reduce the running speed and use high quantities of lost-circulation material (LCM), which caused premature conversion of float equipment from autofill mode to conventional mode (closed-ended pipe) midway, resulting in longer casing run-in time. Surge and swab analysis was conducted to validate equivalent circulating density (ECD) reduction during the casing run and derive a program of operation to safely optimize the casing run.

The surge reduction float equipment package, comprised of a retained flapper valve and ball activation system, allowed the casing to autofill through large flow by areas, tolerant to the LCM in the well, while maintaining compatibility with the subsurface release plug system necessary for deepwater operations. The system allowed for midway circulation, as necessary, to help ensure the fluid level could be maintained during the casing run. The surge reduction equipment set was the first of its kind and consisted of three flapper valves distributed between the float collar and float shoe to provide the necessary redundancy to combat issues with the floats not holding because of the harsh conditions of the operation. It allowed casing to be run at optimum speed and remain within the pore pressure and fracture gradient window. A single deactivation ball installed in the float collar helped ensure the conversion of all valves in both the collar and shoe at the set flow rate, once reaching the planned casing shoe depth. This system combined with high LCM compatible subsurface plug sets not only induced zero losses while performing run in hole (RIH) casing operations (enabling 400% increased casing running speed), it also ensured consistent shoe track integrity with no float valve failure and no wet shoe; this saved several days of deepwater rig time for the operator.

The first ever successful deployment of surge reduction float equipment with a subsurface release plug system in India is discussed, which reduced casing run-in time by up to 22 hours.
Reducing Drilling Risk in Extremely Sour Formations with Novel Scavenger in a Clay Free Non-Aqueous Fluid System
Authors: Nasrallah Mena , Spagnolo Salvatore , Giubertoni Matteo , De Bonis Emanuele , Cavagnero Giovanni , Hafez Mohamed
Published: October 2022

This paper discusses how an organophilic clay-free invert emulsion fluid (OCF-IEF) was customized with a fast-acting hydrogen sulfide (H2S) scavenger to drill a high temperature (HT) exploration well offshore UAE with high H2S concentrations. This application was the first in country to drill through a high H2S formation using an invert emulsion fluid maintaining all parameters within required specifications setting new drilling performance limits.

Exploratory HT wells are associated with notable challenges requiring extensive fluid design and qualification. The additional risk of mitigating high H2S was a key consideration in the fluid design phase. A specialized H2S scavenger was selected based on its fast reaction rates proven through testing. The drilling fluid rheology profile and hydraulics were optimized for HTHP drilling conditions, with the fragile gel structure providing adequate suspension while minimizing pressures running the liner. This paper discusses the design approach to fluid customization in the planning phase and procedures followed during execution ensuring trouble-free performance managing the high H2S risk while drilling an HT Exploration well.

Proper planning and execution, using best-available drilling practices, enabled drilling of this record-breaking well without encountering significant issues that could impact rig time and increase costs. The fast-acting H2S scavenger ensured no acidic gas detection on surface throughout drilling the section, confirmed through continuous Garett Gas Train (GGT) testing on site proving no traces of the acidic gases were left untreated. This fact was confirmed through pressure, volume and temperature (PVT) sampling showing the formation drilled contained 33% H2S. The section was drilled with constant background H2S and CO2 as well as hydrocarbon gas presence and was left open for 82 days with high percentages of gas at every bottoms up. Despite this, no H2S was recorded at surface. The OCF-IEF was subjected to several static periods of up to 145 hours at temperatures between 337°F and 390°F with superior fluid stability which saved on tripping time to condition the fluid prior to logging. Proper planning and risk mitigation were key in the success of this application. The OCF-IEF system proved to be a key success factor in delivering this critical interval due to the narrow clearance while running casing, preventing any surge or swab effects.

The specifically designed OCF-IEF including a fast-acting H2S scavenger displayed superior performance in treating out the acidic gases compared to other scavengers on the market and brought innovation to reality, treating H2S concentrations greater than 33% v/v with no gas released on surface. Successful deployment of this technology in such a challenging environment provides confidence in planning future exploration wells.
15 Years of Foamed Cementing in Oman: Future Applications and Lessons Learned from 270+ Foamed Cementing Operations
Authors: Al Sulaimi Zahra , Al Adhali Sara , Austin Jamie
Published: October 2022

For more than 15 years, foamed cementing has been deployed on wells drilled in the Fahud and Natih fields of North Oman. The production section targets the Natih formation, a fractured Mesozoic hydrocarbon-bearing carbonate sealed by the Fiqa above and the Nahr Umr shale below. The Natih carbonate characteristically requires a cementing design to cure losses while providing zonal isolation. Foamed cement is the standardized cement design used to meet this objective.

Previous attempts to mitigate lost circulation during cement placement using conventional lost-circulation materials were attempted with little success. Since 2006, the advent of foamed cementing has been prescribed as the standard design for cement placement across the 8 1/2-in. production section. These wells have experienced an evolution of stage tools as well as liner packers to aid isolation. The cementing operation consists of a decision tree design approach based on the tools used on the 9 5/8-in. section as well as the quality of wellbore returns observed during cement delivery. The initial stage consists of nitrified water with a foaming agent intended to reduce the hydrostatic burden observed on the fractured formations. This is followed by a four-stage "filler" of foam cement, each with a specific nitrogen rate necessary to maintain the designed density at the final placement depth. If wellbore returns are stable throughout the "filler" phase, the nitrogen rate is reduced to target an ideal final cement density to help ensure the cement sheath has optimized sealant capabilities across the section objective. If wellbore returns are unstable, the final nitrogen stages are maintained, and emphasis is placed on finalizing displacement and choking the backside, as necessary, to maintain foam expansion.

Approximately 270 foamed cement applications were executed in the field using this approach. The acceptance criteria target for this section is for returns to be observed at the surface during cement displacement before packer installation. Continuous lessons learned on design parameters necessary to achieve the objective were captured in the 15-year period discussed. The value added using stage tools versus liner packers was measured and the base slurry designed used for the foam has been modified over time to deliver the highest probability of success for these wells.

Designed cement properties were evaluated and optimized over the 15-year period of foamed cement delivery. Improvement to cement hydration analysis (CHA), permeability, transition time, and expansion slurry properties are discussed.

Additionally discussed, as losses continue to be challenging across these sections, a variation of 11-kPa/m ultra-lightweight foamed slurry designed for wells in the Fahud and Natih production sections are an alternative option for extreme losses observed at > 5 m3/hr before cementing.