bluuebunny/crossref_metadata_2025 huggingface dataset:
Digitally Distanced Inspection & Maintenance at Drilling Rigs : Applied Augmented Reality
Authors: Dash Deepak Kumar , Nair Dileep Chandran , Potluri Srinivas
Published: December 2021

For drilling contractors, the moment of truth is the operations at the site. If the technician at the site encounters a problem he can't solve, then everything stops. The team has to wait for a subject matter expert (SME) to arrive at the site to diagnose rectify the problem. Such process of SME mobilization and till that time Non-Productive Time (NPT) results in loss of hundreds of thousands of dollars. Hence the key challenge is converting the Sparse to Adequate availability of Right Knowledge at Right Time at Right Place, for the support of technicians.

This paper is focused on the approach of moving from Hand Held devices to Hands-Free environment at sites and connecting local/global support to site support systems, to reduce cost, improve HSE and enhance operational performance. The augmented reality technology-enabled, smart glass laced headsets are rugged, zone 1 certified, and are voice-operated which are better than smart tablets which were considered during Technology Qualification Process. Evaluation criteria were: 1. Availability and follow up of the digital work instruction while operating. Moreover, not missing a single step of work instruction while inspection or maintenance continues was noted carefully. 2. Reduced travel/accommodation cost : Normally at the time of shutdown, the rig crew contacts subject matter experts (SME) and (at times) in turn the SME contacts the OEM support team to mobilize service engineers globally. 3. Response time improvement-Availability of support by SME right at the time of need results from better response time to diagnose and fix the issue at hand. Call logging till final resolution process improvement is considered an important metric. Travel restrictions imposed by Covid-19, are also being addressed through the distanced inspection. A hands-free environment is compared vis a vis handheld device. Better training and knowledge transfer are achieved through better communication methods and this goes better with learning by doing. Subsequent text (NLP-speech to text) analysis is planned through deep learning models to derive related predictions. Sparse to Adequate availability of support to rig staff with Right Knowledge at Right Place at Right Time is the key outcome of this Proof of Value project.
Subsurface-to-Economics Closing the Loop on Uncertainty Analysis
Authors: Shergill Galvin , Anton Adrian , Park Kwangwon
Published: December 2021

We are all aware that our future is uncertain. Although some aspects can be predicted with more certainty and others with less, essentially everything is uncertain. Uncertainty exists because of lack of data, lack of resources, and lack of understanding. We cannot measure everything, so there are always unknowns. Even measurements include measurement errors. Also, we do not always have enough resources to analyze the data obtained. In addition, we do not have a full understanding of how the world, or the universe, works (Park 2011).

Every day we find ourselves in situations where we must make many decisions, big or small. We tend to make the decisions based on a prediction, despite knowing that it is uncertain. For instance, imagine how many decisions are made by people every day based on the probability of it raining tomorrow (i.e., based on the weather forecast). To have a good basis for making a decision, it is of critical importance to correctly model the uncertainty in the forecast.

In the oil and gas industry, uncertainties are large and complex. Oil and gas fields have been developed and operated despite tremendous uncertainty in a variety of areas, including undiscovered media and unpredictable fluid in the subsurface, wells, unexpected facility and equipment costs, and economic, political, international, environmental, and many other risks.

Another important aspect of uncertainty modeling is the feasibility of verifying the uncertainty model with the actual results. For example, in the weather forecast it was announced that the probability of raining the next day was 20%. And the next day it rained. Do we say the forecast was wrong? Can we say the forecast was right? In order to make sure the uncertainty model is correct; we should strictly verify all the assumptions and follow the mathematically, statistically, proven-to-be-correct methodology to model the uncertainty (Caers et al. 2010; Caers 2011).

In this paper, we show an effective, rigorous method of modeling uncertainty in the expected performance of potential field development scenarios in the oil and gas field development planning given uncertainties in various domains from subsurface to economics. The application of this method is enabled by using technology as described in a later section.
Usage of Two-Sided Motors as a Part of the Simultaneous Separate Operation Technology
Authors: Uvarov Anton
Published: December 2021

The technology of simultaneous, separate operation is a mandatory condition within the framework of Russian legislation for the production of oil and gas from multilayer reservoirs, which implies a share of a load of several pumps on different reservoirs. To reduce high additional equipment costs and metal consumption of the well, an assembly of two ESPs with one engine was developed. More than forty Russian wells were supplied with double ESP system motors. The project implementation enabled using separate simultaneous operations with more wells and developing reservoirs more accurately. It became possible to develop each reservoir by employing separated data from gauges connected to two reservoirs. The use of two side motors allows using such complicated technologies as separate simultaneous operations for even small and previously not economically achievable reservoirs. According to well inflow calculations, using the most suitable pump, the correct amount of liquid from each reservoir has been produced during these operations.
Using Advance Acid Fracturing Design to Increase the Production Efficiency in a HPHT Reservoir: A Success Story from Southern Mexico
Authors: Figueroa Frank , Mejías Gustavo , Frías José , Brito Bonifacio , Velázquez Diana , Ramírez Carmen , Téllez Fernanda , Briceño Juan , Salas José , Olivares Ángel , Olán Georgina , Flores Andrés , Arroyo Jesús , Busteed John , Hernández René , González Jorge
Published: December 2021

Enhanced hydrocarbon production in a high-pressure/high-temperature (HP/HT) carbonate reservoir, involves generating highly conductive channels using efficient diversion techniques and custom-designed acid-based fluid systems. Advanced stimulation design includes injection of different reactive fluids, which involves challenges associated with controlling fluid leak-off, implementing optimal diversion techniques, controlling acid reaction rates to withstand high-temperature conditions, and designing appropriate pumping schedules to increase well productivity and sustainability of its production through efficient acid etching and uniform fluid distribution in the pay zone.

Laboratory tests such as rock mineralogy, acid etching on core samples and solubility tests on formation cuttings were performed to confirm rock dissolving capability, and to identify stimulation fluids that could generate optimal fracture lengths and maximus etching in the zone of interest while corrosion test was run to ensure corrosion control at HT conditions. After analyzing laboratory tests results, acid fluid systems were selected together with a self-crosslinking acid system for its diversion properties. In addition, customized pumping schedule was constructed using acid fracturing and diverting simulators and based on optimal conductivity/productivity results fluid stages number and sequence, flow rates and acid volumes were selected.

The engineered acid treatment generated a network of conductive fractures that resulted in a significant improvement over initial production rate. Diverting agent efficiency was observed during pumping treatment by a 1,300 psi increase in surface pressures when the diverting agent entered the formation. Oil production increased from 648.7 to 3105.89 BPD, and gas production increased from 4.9 to 26.92 MMSCFD. This success results demonstrates that engineering design coupled with laboratory tailor fluids designs, integrated with a flawless execution, are the key to a successful stimulation. This paper describes the details of acidizing technique, treatment design and lessons learned during execution and results.
Successful Implementation of Low-Pressure Operations LPO Projects: Delivering Low UTC Incremental Oil in Low Oil Price Market
Authors: Narwal Tushar , Kumar Kamlesh , Alias Zaal , Agrawal Pankaj , Busaidi Asaad , Al-Hajri Hamood , Kindi Maryam , Muthalaly Mathen , Mohammed Rabab , Abri Zahir , Al Hadhrami Abdullah
Published: December 2021

Southern Oman has several high pressure (500-1000 bar), deep (3-5 km) and critically sour oil fields (H2S/CO2 up to ~10%/25%). Most of these reservoirs are carbonate stringers encapsulated in salt lacking any natural aquifer support. Field Development strategy for most of the reservoirs in the cluster is primary depletion followed by miscible gas injection. No artificial lift mechanism is installed in these fields, as gas flood is expected to provide the necessary energy later. Many of these fields are depleted and reached lift-die out conditions due to high backpressure from the station. To extend the depletion production life, the team came with Low-Pressure Operation (LPO) project for these fields. This concept was successfully implemented in various fields across the 3 production stations in the cluster. LPO concept is a novel, pragmatic and cost-effective solution to continue production from previous lift die-out wells which is first of its kind in the company. This approach helped to utilize the existing infrastructure and ullage available in the facilities and eliminate the need for installing expensive and complex artificial lifts (e.g. ESP) or depletion compressor systems. This resulted in incremental production at very low UTC and low CAPEX requirements during the low oil price period.
An Integrated and Automated Workflow to Enhance Production Efficiency and Compliance in a Giant Offshore Field
Authors: Zhao Wenyang , Al Qubaisi Salama Darwish , Al Kindi Salem Ali , Al-Feky Mohamed Helmy , Al Shehhi Omar Yousef , Sugawara Yuki
Published: December 2021

Daily production compliance is fundamental to sustain reservoir management excellence and ultimately achieve an optimum oil recovery. The production activities execution is critical to adhere to the reservoir management guidelines and best practices. It is a more challenging task in brownfields due to the limitation of controlling system and limited access especially in offshore fields. A timely and efficient approach is undoubtedly necessary to enhance production efficiency and compliance. An integrated and automated tool has been innovated to analyze and report well production status against the guidelines and requirements in a mature offshore field with more than 50 years history. This systematic approach has been developed through integrating the planned rate, daily actual production rate, latest flow tests, and current well performance. Noncompliance is reported automatically on a user defined time scale, including daily, weekly, monthly or any customized time range within the month time. Daily violation report is generated automatically and sent to production operation for prompt adjustments and other requested actions.

The automated workflow enables both daily production reporting and production compliance reporting. Daily production reporting is a routine work, which usually takes a lot of time every day. The workflow is capable of reducing 90% of the time comparing to the manual way. Production compliance reporting is currently mainly focusing on the comparison of actual production to planned rate and guideline rate. Any exception will be reported as violation. The violation dashboard summarizes the details based on the user selected time range. On daily basis, an email containing the violation details could be generated and sent to the corresponding teams for corrective actions. In this giant brown field, production GOR is a primary controlling parameter. The latest flow tests have been taken into account to evaluate the gas production compliance. Any violation to the GOR guidelines will be reported in the same communication email for timely correction. With the innovated tool, the violation ratio of the giant offshore field has been successfully reduced and controlled. The usual responding time for corrections has been dramatically reduced from months to days.
Stimulation Workflow Applied on LAPA Pre-Salt Carbonate Field Deep-Water Brazil
Authors: Pedrosa Hélio Alves , Colbert Felipe Costa , Garcia Fernando Marques , Gachet Raphael Fernandes , Boldrini Alberto Carlos , De Souza Jose Marcio , Carrara Marcelo Oliveira , Okullo Ruhhiyyih Audi , Belisario Joan Hernandez , Lacerda Ly Amaury , Goyallon David
Published: December 2021

Lapa is a pre-salt deep-water field located around 270km off the coast of São Paulo, Brazil at Santos basin. This carbonate reservoir lies in water depths of around 2,100m and can produce good quality light 26° API oil. The stimulation in large carbonate reservoirs is very challenging, and techniques used for Lapa were based on chemical divergence. The development in offshore environments requires proper planning, execution, and monitoring to achieve the desired results and, of course, profitability.

The matrix acidizing method was chosen to stimulate all wells of this campaign (2 producers and 2 injectors). This method consists of bypassing formation damage and stimulating the reservoir by creating wormholes via chemical pumping. In the design phase, stimulation operations previously performed at this field were reviewed, analyzed, and optimized. The main changes were regarding the completion strategy without the use of coiled tubing and placement during the completion phase as it could optimize the time and the cost for the project. The volumetric rate (gal/ft) was also reduced and the selection of the main fluid changed after several laboratory analysis and software simulations.

The Lapa field requires high fluid volumes due to the length of the intended treatment interval. The assembly of a stimulation plant on a supply vessel from operator fleet (multi-purpose FSV – field support vessel) was the most cost-efficient approach to address the high volumes required as there was no Well Stimulation Vessel (WSV) available "on call" in the Brazilian offshore market at that time. This solution could also optimize the vessel fleet while the vessel was not required for pumping as FSV was also equipped with ROV and was mean to carry subsea planned task. The fluid test strategy was also a key point for this successful project as many tests were performed to make sure that the correct fluid system was selected. During this process, several fluid systems and different formulations were submitted for core flow tests and dual core flow tests to evaluate worm holing efficiency of retarded fluids and diversion performance of Chemical diverters. Compatibility tests were also performed, and a mud cake breaker was developed locally, especially for this project.

This paper will bring an overview of all aspects regarding Lapa stimulation project since the conception, fluid system selection, laboratory tests, lessons learned and the potentially future strategy for this field.
Smart Crude Desalter Monitoring System Using Capacitance Based Technology
Authors: White Ramsey James , Al-Hamoud Abdullah Abdulrahman , Lopez Miguel Angel
Published: December 2021

Saudi Aramco operates several electrostatic coalescers for bulk emulsion separation and crude desalting. One of the major challenges in operating electrostatic coalescers is the potential buildup of tight emulsions and a rag layer at the interface layer, which causes short-circuiting of the electrostatic grids which increases the risk excessive carryover of water with the crude. Conventional liquid level instrumentation cannot measure the thickness of emulsion layers since the level taps are at the clean oil and water layers. Consequently, the buildup of emulsions is normally not detected by operators.

A capacitance-based emulsion detection system was installed at one of the electrostatic coalescers of a Saudi Aramco facility. The system is comprised of multiple probes installed at various elevations in the vessel. Each probe measures the capacitance of the liquid in which it is immersed in. The data is then transmitted to the DCS, where an algorithm computes the oil/water content. Saudi Aramco developed an enhanced predictive alarm logic and advisory tool using the measured capacitance data so that operations may take preemptive measures to prevent upsets from occurring.

The alarm system was tested over an extended period of time and it has shown that it can accurately detect the buildup of emulsions prior to an upset in the electrostatic coalescer. What is unique about the system is that it utilizes a combination of absolute capacitance measurements and capacitance variations in the algorithm. Emulsion buildups are detected by the alarm system hours before a potential upset, providing operators ample time to take preemptive measures such as increasing the demulsifier injection rate, desludging the vessel or lowering the interface level. The system significantly reduced the number of electrostatic coalescer upsets at the facility and crude quality was enhanced. Upon inspection of the probes during shutdowns, no buildup of deposits, which impacts capacitance readings, were found on the probes since a flushing system was installed. The alarm system has been utilized for four years with no major issues.

Utilizing the capacitance probes to develop an algorithm for an alarm system is a novel technique to detect emulsion layer buildup hours prior to a potential electrostatic grid upset. Large-scale deployment is more economical as it is more cost-effective than radioactive profilers and is logistically easier to manage.
Remote Internet Coverage through Satellite Broadband
Authors: Palit Sujoy , Alteneiji Sherooq Saleh
Published: December 2021

Present day industries worldwide, including oil and gas sector, are going through a transition from the traditional concept of isolated operation to a more cohesive and interconnected digital transformation. The driving forces behind the transformation can be summarized as follows: -A collaborative workplace spanning multiple locations, where the processes can be synchronized through an integrated work management system-Reduced deployment of manpower to remote and hazardous locations through implementation of remote monitoring and control from a central location-Providing intelligent guidance to operation and maintenance through implementation of training, real-time troubleshooting etc.-Informed decision making through historical data, real-time video, lessons learnt etc.-Storage and mobility of data, efficient computing and distributed workload-Machine substitution of human performance (artificial intelligence, drones, robots etc.)

From all these drivers, evolves the concept of Internet of Things (IoT). On the field side, the idea of IoT means to deploy web-enabled devices having unique addressable identity. A plethora of such field instruments, devices, machines, processes and people then need to be interconnected over internet through a robust and reliable telecom infrastructure to make such integrated platform happen. Therefore, on the backbone side, this complex mesh of interconnectivity largely depends on the availability of a feasible and practical communication media. Providing a viable communication media becomes more challenging with the constraints of locations involved – their remoteness, difficult terrains, prevalent hazardous atmosphere, to name a few.

The objective of this paper is to present one such communication scheme through VSAT, which is easy to deploy, economically viable, scalable with growing demand and based on emerging technology of private satellite communication. For the sake of objectivity, this paper discusses most of the scenarios with an offshore oil and gas field, although the idea can be generalized to apply on other sectors and industries.
AR Gauge Scanner Mobile Application
Authors: Althobaiti Abdulrahman , Abdellatif Fadl , Alrasheed Ali , Trigui Hassane , Alsaadi Ahmed , Patel Sahejad
Published: December 2021

This paper showcases an innovative mobile application powered by IR4.0 technologies including augmented reality (AR) and artificial intelligence (AI). The purpose of this application is to enable digital transformation of analog gauges, digitize their measurements, automate historical data storage, visualize trends, and provide useful information about the gauge to the operator. Utilizing this application will replace the current practice of manual recording of readings in order to reduce human errors as well as promote operational efficiency.

With this application, the operator simply points the mobile device's camera towards the gauge and the image is converted to a digital measurement using computer vision algorithms. The digitized readings are sent to a remote database for recordkeeping and data analytics. In order to identify which gauge is being scanned, which is necessary for proper recordkeeping, the application detects a unique QR-code tag attached to the gauge. Additionally, the application utilizes AR technology to overlay gauge specific information (such as gauge type, safe operating range, fluid type, etc.) along with the digitized reading. Visualization of historical readings is another feature in the application that assists the operator in trend monitoring and decision making.

Preliminary tests for the prototype application were carried out in a laboratory environment to demonstrate the working principle of this application. Although the technology is in its early stages of development, it shows promising results in terms of accuracy and speed of the computer vision algorithms to detect and digitize the analog gauges. The historical data recorded by the application can also be accessed via the control room using a web interface, where information from various gauges can be retrieved and visualized for analysis and monitoring. Overall, the presented application integrates computer vision and augmented reality to provide an effective solution for digitizing analog gauges while promoting digital transformation efforts within the industry.
Innovative Use of Wireline Tools Enables Successful Re-Entry on Subsea Wells
Authors: Ragaglia Simone , Napoleone Luca Luigi , Carotenuto Antonio , De Dominicis Guerino , Luppina Salvatore , Mangione Alessandro , Faraoun Abderrahmane , Mourani Houssam , Allegretti Gianluca
Published: December 2021

Re-entry of subsea wells can always hide unforeseen difficulties. Contingency mobilization of coiled tubing (CT) usually gives a wide spread of solutions to overcome most of the possible events.

However, when operating on a winterized semisubmersible rig in the remote fields of the Barents Sea, rig-up of CT spread can be costly and complicated. Furthermore, lighter and easily deployable wireline powered mechanical tools have proven to be effective in tackling most of the possible challenges. Possible tubing obstruction issues can be resolved via clean-out/suction, pumping, or milling methods. In this instance, all three were used with different tools to clear the obstruction from the tubing and to clean with precision inside an internal fishing profile of a well head barrier plug to allow for well access.

The first challenge encountered when re-entering the tubing in Well-1 was the presence of a 151m long hydrate plug. It was easily removed by an e-line tool capable of applying 10 bar of dynamic underbalance, while maintaining a continuous flow circulation. Such an application is a novel development in the use of existing tools.

After removing the hydrate plug, it was discovered that the tubing was plugged by 246m of wax deposits, which were preventing communication with the reservoir. To overcome this problem, a jetting tool was utilized to continuously pump fresh wax solvent inside the landing string. Pumping continuously fresh wax dissolvent provided a unique and effective means to mechanically and chemically remove a significant obstruction.

Once the communication with the reservoir was re-established, an additional obstruction of almost 129m (resistant to the wax dissolvent) was encountered. To overcome this challenge an e-line milling tool was utilized, and the resulting debris was bullheaded down into the reservoir.

Similarly, when re-entering Well-2 a challenge was encountered to pull a barrier plug due to debris deposits inside the internal fishing profile. Both e-line milling and suction tools were sequentially used to resolve the problem and prepare the plug for retrieval.

The tools used were already available on the market for different applications. In this case the tools were used in an alternative way, using their features to solve issues beyond conventional expectations. The result fosters confidence to plan future re-entry without the need for mobilizing a CT spread.
Carbonate Karstified Oil Fields Geological Prediction and Dynamic Simulation Through Equivalent Relative Permeability Curves
Authors: Tarantini Vincenzo , Albertini Cristian , Tfaili Hana , Pirondelli Andrea , Bigoni Francesco
Published: December 2021

Karst systems heterogeneity may become a nightmare for reservoir modelers in predicting presence, spatial distribution, impact on formation petrophysical characteristics, and particularly in dynamic behaviour prediction. Moreover, the very high resolution required to describe in detail the phenomena does not reconcile with the geo-cellular model resolution typically used for reservoir simulation. The scope of the work is to present an effective approach to predict karst presence and model it dynamically.

Karst presence recognition started from the analysis of anomalous well behaviour and potential sources of precursors (logs, drilling evidence, etc.) to derive concepts for karst reservoir model. This first demanding step implies then characterizing each cell classified as karstified in terms of petrophysical parameters. In a two-phase flow, karst brings to fast travelling of water which leaves the matrix almost unswept. This feature was characterized through dedicated fine simulations, leading to an upscaling of relative permeability curves for a single porosity formulation.

The workflow was applied to a carbonate giant field with a long production history under waterflood development. Firstly, a machine learning algorithm was trained to recognize karst features based on log response, seismic attributes, and well dynamic evidence, then a karst probability volume was generated and utilized to predict the karst presence in the field. Karst characterization just in terms of porosity and permeability is sufficient to model the reservoir when still in single phase, however it fails to reproduce observed water production. Karst provides a high permeability path for water transport: classical history match approaches, such as the introduction of permeability multipliers, proved to be ineffective in reproducing the water breakthrough timing and growth rate. In fact, the reservoir consists of two systems, matrix, and karst: however, the karst is less known and laboratory analysis shows relative permeability only for the matrix medium. The introduction of equivalent or pseudo-relative permeability curves, accounting for both the media, was crucial for correct modelling of the reservoir underlying dynamics, allowing a proper reproduction of water breakthrough timing and water cut (WCT) trends.

The implementation of a dedicated pseudo relative permeability curve dedicated to karstified cells allowed to replicate early water arrival, thus bringing to a correct prediction of oil and water rates, also highlighting the presence of bypassed oil associated with water circuiting, particularly in presence of highly karstified cells.
Novel Data-Driven Methodology for Production Allocation Calculation Utilizing Physics-Based Models Coupled and Integrated Within a Digital Framework
Authors: Alsaeedi Ayesha Ahmed Abdulla Salem , Elabrashy Manar Maher Mohamed , Alzeyoudi Mohamed Ali , Albadi Mohamed Mubarak , Soni Sandeep , Isambertt Jose , Tripathi Deepak
Published: December 2021

Determining the production from each well is crucial for financial and technical purposes. Moreover, this production can be anticipated using several different techniques. This paper describes the procedures to calculate the production allocated to each well in a giant gas-producing field by utilizing physics-based models that are orchestrated in a dynamic digital platform to provide a robust and efficient solution.

The cases for this study of allocating gas rates to individual wells were performed using a digital platform as the primary tool utilized to account for the main productional location factors such as well tests and events that are used to estimate actual production volumes. Subsequently, relevant data is extracted, filtered, and loaded into the system in a dynamic interaction with fewer human interventions. The methodology for calculating the production allocated followed these main steps: a) Determine production per well under existing possible measures, b) Determine well contribution factors, c) Distribute actual rates and production according to allocation factors.

By using polynomial equations where the inflow performance of the gas wells was verified, the allocation rates were calculated at every desired point of the network. Having an integrated platform proved to be advantageous since it provided a seamless link between different relevant manual and real-time databases and well / network models bringing unique capabilities and benefits. While comparing this integrated and holistic approach versus the previously established one, it was highlighted that production allocation using mainly choke sizes and well test as a sole source for well production can bring significant variations. This creates production mismatches at the well level; therefore, it portrays a misrepresentation of the actual field conditions. Numerous challenges, which are usually faced while calculating the production allocation process, were overcome during the development of this study, such as frequent surface network changes, lack of databases communication, and daily variations on the on/off wells’ status. Furthermore, the data management capabilities of the framework allowed data to be quickly accessible by the users whenever needed allowing them to visualize across the different teams and departments, taking actions when and where required.

This standardized methodology provided consistency, reliability, and accuracy, which can be replicated on oil-producing fields and networks; it can be enhanced and scaled in order to incorporate other business processes such as well allowable calculation and voidage monitoring.
Evaluating Small vs. Large Power Blocks for Pipeline Compression Stations
Authors: Chhibber Gautam , Dave Mayank Kumar
Published: December 2021

This paper discusses how the application of large, gas turbine-based power blocks (>50,000-hp) in pipeline compression stations can contribute to lower capital costs, improved lifecycle performance, and reduced carbon emissions. For illustrative purposes, two compression facility power block configurations (nine 30,0000-hp trains vs. five 55,000-hp trains) are compared on the basis of capital expenditures (CapEx), operating expenditures (OpEx), availability, efficiency, and operating flexibility. A summary of the study's results are as follows:

– Net present value (NPV) analyses show that 5x55,000-hp ISO trains can result in up to $50 million reduction in CAPEX vs 9x30,000-hp ISO trains – By having fewer trains, operations & maintenance (O&M) costs can be reduced by as much as 20% – Lifetime fuel savings with a 5x55,000-hp train configuration vs. 9x30,000-hp trains are estimated at $40 million, owing to the increased operating flexibility of modern gas turbines, even at partial loads.

The paper will also present considerations for digitalization, modular construction, and package integration – with a particular focus on how these measures can be leveraged to lower execution risk and enhance the lifecycle performance of gas turbine-driven compression trains.
Developing Organizational Workforce by Successfully Facing and Overcoming Current Challenges
Authors: Yanez Banda Maria Eugenia , Espina Gotera Francisco Javier
Published: December 2021

During the year 2018, an operator evaluated the career paths and professional development of its technical personnel, extending its evaluation to how the contracting department acquired such training, which wasn't consistent with regard to a training provider, training topics, course agendas or training delivery.

Some of the main challenges in providing training are the engineers’ availability to attend classes and the scheduling constraints throughout the operator's five field locations. As an example, planning a class in the current organization might not reach the entire intended audience within the desired time frame because that class may only be scheduled in one of the five locations, and the engineers from the other four locations would need to travel to attend it. The impact of this may be that without the advantage of travelling to attend a specific training, the engineer may not be able to achieve all the promotional requirements for the next step in his/her career path.
World's First Successful Coiled Tubing Intervention to Stimulate Four Laterals in a Single Trip
Authors: Matar Khaled M. , Al-Mutairi Abdullah B. , Khandelwal Nakul , Chawla Sapna , Alkreebani Mohammad , Robles Fernando , Al-Obaidi Abdul Mohsen , Al-Otaibi Khaled , Al-Azmi Mohammad , Al-Mehanna Mehanna , Saleh Buthainah , Al-Bahar Zakaria , Abdul Azim Shaikh , Attia Adel
Published: December 2021

Drilling a multilateral well is generally recommended for several reasons such as achieving higher productivity indices and improving recovery in tight, low-permeable zones. While the many benefits of multilateral wells are attractive, they also have drawbacks which make these wells challenging. A key challenge is how to effectively stimulate all the laterals after they have been drilled. This paper presents the application of a unique intervention technique in a multilateral well to stimulate several laterals in a single run.

To increase reservoir contact area the operator drilled a multilateral well composed of 4 legs. This was carried out despite the absence of proven ways to stimulate each lateral individually. This intervention would also present the following challenges:

Well displacement and stimulation would require multiple re-entries into each lateral, all conducted from a drilling rig. All the laterals were known to branch off from the low side of the bore, so individual lateral and main-bore selection would be complex. Extended reach laterals require accurate friction lockup modelling and mitigations.

The unique solution presented in this paper includes the use of real-time Hybrid cable coiled tubing (RTHCT) technology. This incorporates a hybrid cable installed in the coiled tubing (CT) string and a modular sensing bottom-hole assembly (MSBHA). Electrically controlled indexing tool, inclination sensor, tool-face sensor, and hydraulic knuckle joint were used as part of the BHA to enable real-time diagnostics and dynamic controls from surface to successfully enter the lateral legs. The MSBHA enabled the orientation of the BHA electrically to any position required using software to determine and control the exact position of the BHA.

This paper presents a solution to all the above-mentioned challenges. It discusses the successful implementation of the RTHCT to displace and stimulate all the 4 laterals in a single CT trip in less than seven days, pumping over 7,000 bbls of various chemical systems and covering an open-hole length of 11,176 ft. Unlike other technologies, the RTHCT technology confirmed entries into the laterals without the need to tag the bottom of the lateral, saving substantial time.

Enabling re-entry in these 4 laterals represented a world record translating into major efficiency improvements and cost savings for the project. This intervention also represented the first time in Kuwait that more than 2 laterals have been accessed in a CT run.
Gap Analysis on MEES Execution
Authors: Singh Kamaljit , Paul Raju , Kamal Faris , Takeiddine Ousama
Published: December 2021

Main Electrical Equipment Supplier (MEES) concept has been adopted on mega projects to facilitate overall electrical power system integration and standardization of items/systems within an EPC package as well as across multiple EPC packages and to avoid interface issues. A gap analysis has been performed in this paper based on experience on recent projects and recommendations are proposed as mitigation measures which will benefit Clients, Suppliers as well as FEED/EPC CONTRACTORs.

Challenges faced during execution are categorized based on type as well as execution stages. Paper focusses on the major items to be defined as part of the frame agreement during MEES selection to minimize conflicts and issues later on. MEES package pricing (including material, non-material items and services) is done based on agreed Price Book. Gaps are identified as part of this paper including the methodology for change management. Scope limitation is also discussed in detail with clear objective of minimal risk to all stakeholders. Timing and responsibility of MEES selection, that is critical on mega projects with multiple packages, has also been analyzed.

Concept of MEES is highly recommended on projects that have complex electrical power system, projects involving multiple EPC CONTRACTORs and also on the projects that are fast track in nature. It has been observed that most projects these days fall into one of these two categories which makes this paper even more relevant. However, execution of MEES package has vast scope for improvement.

As part of MEES selection, the following shall be agreed and established, as a minimum:

Selected make & model list of all the components along with the unit rates as part of MEES frame agreement that acceptable on project. Price book including all the main equipment envisaged on the project fully complying with project requirements. Comprehensive technical deviations acceptance list as part of MEES frame agreement. Technical compliance certificate indicating Vendor's compliance on the latest revision of Specifications/Data Sheets/ drawings associated with MEES Material Requisition (MR).

Price Book should be sufficiently comprehensive without gaps to avoid variations after award. Most common gaps are identified and discussed in detail in the paper. It is highly recommended to select MEES during FEED stage (prior to bidding stage) in order to take advantages in terms of project schedule, change management and overall cost optimization.

MEES concept, if managed with recommendations in this paper, can benefit all stakeholders.
Well Automation Based on Flaring
Authors: Patni Surabhi , Kumar Sharma Vinay
Published: December 2021

At a subsurface level, controlling uneven production and early gas breakthrough are big challenges. It is very difficult to achieve the target production while preventing unnecessary flaring from high gas to oil ratio (GOR) wells. To keep the associated gas within surface compression capacity, the High GOR wells are shut in or partially choked by production programmers through a manual work-process, which doesn't always give optimum results.

PDO developed a control solution to ensure produced gas always remains within surface compression capacity while ensuring maximum production. The solution achieves this by continuously monitoring flaring and choking the high GOR wells whenever needed. It does this sequentially from highest to lowest GOR wells choking is done to an optimum level by controlling its flow line pressure above certain target.

The concept revolves around automating production programmer's task and optimizing it via continuous monitoring and control in DCS, which allows wells to deliver the full potential up to the surface facility constraints with reduced operator intervention.

This novel idea is to integrate subsurface and surface facility Optimization via well control. This was implemented in two of the assets in PDO where frequent flaring was identified. Both facilities have limited compression capacity and number of high GOR wells out of several Gas Oil Gravity Drainage (GOGD) producer wells. In order to achieve the goal of "Zero" flaring, the wells are choked in order from highest to lowest GOR, automatically, up to the optimum limit set by either their respective flow line pressures or to defined lower optimum limit, and optimize the production by opening the wells up to its optimum target, when there is no flare. The similar concept is now being replicated in other assets following a LEAN approach.
The Selection and Optimum Well Testing Practices to Achieve Zero Flaring & Venting in Malaysian Water for a Petronas Field Development
Authors: Naharindra Adhi , Ali Zalina , Sapi’an Nik Fazril Ain , Riyanto Latief , Tusimin Fuziana , Ahmad Mior Yusni , Zaiga Sariman Mior , Sarical Dolores , Baharuddin Nurbaiti
Published: December 2021

Increased HSE concerns and global economic efficiency from well testing activities especially on its environmental impact have left several oil and gas industries’ facing critical challenges to develop and monetize oil reserves. Some of these challenges include handling well effluents from well test unloading operations after well completion with high contaminants such as H2S and CO2 which will exacerbate environmental impact to safety, pollution, and oil spill risks. In addition, mitigation to environmental impact will be constrained to limited deck space and topside loads for offshore wellhead facilities and eventually restricts the footprint of well test unloading equipment.

The scope of the paper is to examine the evolution of well deliverability testing from conventional well test facilities’ flaring practices to contemporary smokeless and zero flaring operations applied in a giant sand stones oil field in Malaysian water, which is surrounded by a world class environmentally protected marine and coastal ecosystem. The zero-flaring approach allows a demonstration of the safety & emission reduction, cost saving, technical viability, and economic benefits over traditional flaring techniques for 20 to 30 well testing during the life of field.

Previous wells clean up method require flaring of oil and gas before the production facilities and flow lines were operational.commissioned. The application of environment friendly well testing system using the completed flow lines and production facilities enable zero-flaring option to be technically and economically viable. Zero-flaring well testing system provides several attractive benefits, with potential reduction in flaring equivalent of ±1000 barrels of oil, pollution avoidance, 40 - 50% schedule reduction and over 40% reduction in total project costs for the field development..
Retrofitting Offshore Drilling Rigs with Islanded DC Grids and Energy Storage
Authors: Settemsdal Stig , Ventrelli Saverio
Published: December 2021

The paper presents a novel approach for modernizing/retrofitting offshore drilling rig power plants with islanded direct current (DC) power grids and energy storage. The concept has been successfully applied on several offshore rigs which are in operation today and is applicable to jack-ups, semi-submersibles, drill ships, as well as other types of marine support vessels for oil and gas platforms and wind farms.

The approach aims to enhance the feasibility of leveraging energy storage solutions on offshore drilling rigs and marine vessels by making use of the existing power plant footprint. Unique measures have also been incorporated into the electrical system architecture to ensure that the reliability and safety of the existing alternating current (AC)-based system are not compromised. This enables operators to capitalize on the numerous benefits of energy storage (e.g., reduced emissions, enhanced dynamic performance for drilling and dynamic positioning, etc.) without having to perform a "rip and replace" of the entire power plant and electrical infrastructure.
Predictive Analytics Method Underpin Planning and Budgeting Evolution
Authors: Wang Zhehao , Jobarah Hussain
Published: December 2021

Predictive analytics has a wide range of applications in many industries operating on a routine basis. The oil industry is in a state of constant evolution, with events in 2020 being the highlight of volatility and unpredictability. The main objectives of this paper showcase that improved predictive analytics method can serve as the foundation within the decision-making process, that leads to the goal of accuracy planning and cost-effectiveness in the oil and gas industry.

The initial step of the improved methodology is utilizing data, statistical algorithms, and machine learning techniques to build a financial model capturing essential trends. The budget is forecasted based on the basket of weighted factors, including historical data, request of capital expenditure, operating cost, and other factors. The core is at the reviews of portfolio optimization. It focuses on rebalancing cash priorities to reduce capital and operating expenditures driven by new technology, cost savings, and project schedule revision. The vital step is the separation of operating costs from capital investment. A periodical review is imperative to capture the ad-hoc significant events.

Utilizing the above improved predictive analytical methods helps to increase the accuracy of planning and budgeting. It is also time-efficient for the decision-maker to identify the focused area or benchmark with peers based on the trend derived from predictive analysis. Meanwhile, the scorecard and subject matter experts review ensures that the selected tasks are strategically aligned with the organization's short-term target and long-term goals. Portfolio optimization reviews contribute to substantial savings in both capital and operational spending. Periodical reviews can timely identify the deviation, include those variances in the module, and provide a practical year-end forecast.

Changes do not happen over the night. It is time-efficient and cost-effective to apply improved predictive analytics during the decision-making process to make financial planning and budget based on the trend and a series of well-defined factors. Those factors should be qualified as well as quantified after internal reviews.