bluuebunny/crossref_metadata_2025 huggingface dataset:
First Multilateral Well in the Most Congested Field in Abu Dhabi, Case of Study
Authors: Castillo Felix Leonardo , Sarhan Mohamed , Saify Abd El Fattah El , Aguilar Victor Jose , Bethancourt Roswall Enrique , Ferrer Gennadys , Cortes Alejandro , Bacina Bojan , Sudiro Hartoyo
Published: December 2021

This paper will highlight the first level 2 Multi-lateral well in BAB Field with permanent limited entry liner completion in the lower borehole to enhance accessibility and production. The well presents a technical milestone to the company in the development of multiple reservoir by combining two (2) wells from different reservoir and produce from both by using same surface well construction.

At initial stage, the economics related to the implementation of the multilateral approach were analysed. Calculation was done by comparing the cost related to the technology application against the cost to prepare one (1) location plus completing a well up to the 7" liner and mobilizing the rig twice. Then, it was necessary to select the candidate wells to be drilled from the same slot where synergy between Study team and drilling team was in place in order to ensure proper target alignment to make feasible the drilling and completion operations at the same time that the production targets were fulfilled.

This project confirmed the feasibility of multilateral well application in a very congested field in terms of wells construction and surface facilities. In order to achieve such goal full synergy must be in place to select proper wells candidates and align targets.

Cost reduction is massive considering the elimination of three (3) well phases plus avoidance of one (1) location construction and also the elimination of 1 rig move represents a big impact in terms of economics. Furthermore, the impact in terms of the risk reduction must be considered

By combining two (2) wells in one (1) and eliminating three (3) phases in the standard well construction the harmful impact of location preparation, drilling fluids and cuttings on the environment is reduced by 45%, especially with oil base mud system.

Geological problems can be observed during drilling each phase of a new well. However, drilling multilateral wells will reduce this occurrence.

Well was completed with 7"× 4-1/2" top packer, 4-1/2" Slotted tubing and seven (7) swellable packers in lower borehole as well as Dual upper completion with 7" single retrievable and 9-5/8" dual retrievable packer and 2-7/8" and 3-1/2" tubing combination in both short and long string.

This paper presents ADNOC Onshore first and successful experience in the deployment of new acquired technology for the Drilling multi-lateral / dual completion systems in BAB Field. The screening criteria for selecting the system as well as the benefits realized and lessons learned from this experience are also discussed together with the design simulations required to ensure the success of the well construction.
Development of New Corrosion Inhibitors Using Robotics with High Throughput Experimentation Methods
Authors: Obeyesekere Nihal U , Wylde Jonathan J
Published: December 2021

Critical micelle concentration (CMC) is a known indicator for surfactants such as corrosion inhibitors ability to partition from two phase systems such as oil and water. Most corrosion inhibitors are surface active and at critical micelle concentration, the chemical is partitioned to water, physadsorb on metallic surfaces and form a physical barrier between steel and water. This protective barrier thus prevents corrosion from taking place on the metal surface When the applied chemical concentration is equal or higher than the CMC, the chemical is available in aqueous phase, thus preventing corrosion. Therefore, it was suggested that CMC can be used as an indicator of optimal chemical dose for corrosion control1. The lower the CMC of a corrosion inhibitor product, the better is this chemical for corrosion control as the availability of the chemical in the aqueous phase increase and therefore, can achieve corrosion control with less amount of chemical. In this work, this physical property (CMC) was used as an indicator to differentiate corrosion inhibitor performance.

The corrosion inhibitor formulations were built out by using combinatorial chemical methods and the arrays of chemical formulations were screened by utilizing high throughput robotics 2-4, using CMC as the selection guide. To validate the concept, several known corrosion inhibitor formulas were selected to optimize their efficacy. Each formula contained several active ingredients and a solvent package. These raw materials were blended in random but in a control, manner using combinatorial methodologies. Instead of rapidly blending a large number of formulations using robotics, the design of control (DOE) methods were utilized to constrain the number of blends.

Once the formulations were generated by DOE method, using Design Expert software that can effectively explore a desired space. The development of an equally robust prescreening analysis was also developed. This was done by using the measurements of CMC with a high-throughput screening methodology. After formulation of a vast array of formulation by using Design Expert software, the products were screened for by CMC using automated surface tension workstation. Several formulations with lower CMC than the reference products were selected.

The selected corrosion inhibitor formulations were identified and blended in larger scales. The efficacy of these products was tested by classical laboratory testing methods such as rotating cylinder electrode (RCE) and rotating cage autoclave (RCA) to determine their performance as anti-corrosion agents. These tests were performed against the original reference corrosion inhibitor.

The testing indicated that several corrosion inhibitor formulations outperform the original blend thus validating the proof of concept.
Biogas Plant Digital Transformation Using Edge-Computing Batteryless and Free of Maintenance Atex Iot Powered by Heat
Authors: Aragones Ortiz Raul , Nicolas Alegret Roger , Oliver Parera Maria , Oliver Malagelada Joan , Malet Munté Roger , Comellas Vogel David , Ferrer Ramis Carles
Published: December 2021

Current industries leave a big ecological footprint that needs to be reduced to preserve our resources. For it, big industries are leading new researches to move to more environmental-friendly technologies.

In this paper we explain an innovative technology which has the ability to introduce edge-computing in the node in combination with energy harvesting, which allows the device to work without the need of batteries. Also, as all the computations are performed in the node, it allows the use of long-range communication protocols. To demonstrate the behavior of the technology, the paper also presents two cases of use in facilities.
First Successful Pilot Testing of Unconventional Reservoir in North Kuwait from Scratch to Productivity
Authors: Ahmed Zamzam Mohammed , Salem Abrar Mohammed , Ramon Jose , Wu Liu Pei , Mowad Benjamin
Published: December 2021

Jurassic's kerogen shale-carbonate reservoir in North Kuwait is categorized as a source rock exhibiting micro- to Nano Darcy permeability and is Kuwait Oil Company's focus in recent years. Although the challenges are significant (formation creep, fracturing initiation, etc.), the efforts toward producing from unconventional reservoirs and applying experience from both USA and Canada in this field are ongoing. As a step toward development, the gas field development group selected a vertical pilot well to measure the inflow of hydrocarbon from a single fracture while minimizing formation creep (flowing of particulate material and formation into the wellbore that blocks the production). This step was required prior to drilling a long horizontal lateral wells and completing it with multiple hydraulic fractures to confirm commercial production.

A comprehensive design process was executed with the full integration of operator and service company competencies to achieve the three main objectives: First, characterize the kerogen rock mechanics which allows selection of the most competent kerogen beds to prevent collapse of the hole during fracturing (creep effect) by conducting scratch, unconfined stress, proppant embedment, and fluid compatibility tests. Then, prepare a suit of strength measurements on full core samples to help in fracturing design and minimize creep effect. The second objective was to design and implement a robust proppant fracturing program that avoids the kerogen concerns after selecting the most competent reservoir unit and suitable proppant type. Third, perform controlled flowback to unload the well and attempt to establish clean inflow unlike previous attempts that failed to either suitably stimulate or prevent solids production (deliver clean inflow).

After analyzing the lab test results, choosing the optimal fracturing design, and preparing the vertical well for proppant hydraulic fracturing, the treatment was performed. In December 2019, the hydraulic fracturing treatment with resin-coated bauxite proppant was successfully pumped through 6 ft of perforation interval and followed by a controlled flowback. Resin-coated bauxite proppant was specifically selected to overcome the creep and embedment effects during the fracture closure and flowback. Moreover, a properly designed choke schedule was implemented to balance unloading with a delicate enough drawdown to avoid formation failure. This paper discusses in detail the lab testing, evolution of fracturing design, treatment analysis, and the robust workflow that led to successfully achieving all main objectives, paving the way for long horizontal lateral wells. This unconventional undertaking in Kuwait presents a real challenge. It is a departure from traditional methods, yet it points toward a high upside potential should the appraisal campaign be completed effectively.
Energy Performance Benchmarking of Process Refrigeration Units
Authors: Sajjad Saqib , Ali Haseeb
Published: December 2021

Process refrigeration units are one of the major energy consumers at gas processing plants. Owing to the higher energy consumption, evaluation and benchmarking of energy performance of the refrigeration units is very important for identification of energy saving opportunities. In this regard, an energy performance benchmarking study was performed by detailed assessment and evaluation of the existing process refrigeration units to identify potential of energy efficiency improvement.

The study encompassed twenty-one (21) process refrigeration units installed at five (05) different sites. The methodology included collection and analysis of design & operation data and review of key variables like percent load, anti-surge valve opening, condensing temperature & pressure and chilling temperature etc. Energy Performance Indicators (EnPIs) considered for the benchmarking were compressor's specific energy, coefficient of performance (COP) and relative COP (RCOP). A thermodynamic model was developed for each unit to ascertain the refrigeration load.

Instead of usual high level benchmarking techniques, the study considered unit and equipment level benchmarking which provided better insight of the systems and helped in finding opportunities for energy efficiency improvement. Further, COP which is generally considered as a benchmarking EnPI, only considers refrigeration load and energy consumption, whereas, this study introduced a new EnPI named "Relative COP" which additionally takes into account the chilling and condensing temperatures and gives true energy performance benchmarking.
Novel Motor Adjusts Bend Setting Downhole, Addressing Today's Directional Drilling Challenges
Authors: D'Souza Rohan , Emuchay Chigozie , Neil Paul , Clausen Jeffery
Published: December 2021

Previously, few options existed for the complex directional challenges. Drillers either needed to rely on multiple Bottom Hole Assemblies (BHAs) or use expensive drive systems, which resulted in increased operational cost and limited drilling flexibility. This novel Downhole Adjustable Motor (hereafter referred to as downhole adjustable motor or the motor) described in the paper addresses these limitations by enabling the driller to change the motor bend in real-time downhole. In addition, the motor can deliver up to 1,000 horsepower (HP) at the bit during rotary drilling—the highest power in its size range. This paper will review how, even in harsh drilling applications, the downhole adjustable motor has proven to save trips, increase bit life, reduce lateral vibrations and stick-slip, and allow for drilling optimization to increase Rate of Penetration (ROP) and decrease overall drill time. Whether for drilling contracts or lump-sum turnkey projects, the directional drilling industry benefits from this new technology's ability to improve drilling economics while increasing safety by reducing drillpipe tripping and additional BHA handling.
Introducing New Concepts in Red Zone Management
Authors: Balbaa Ola , Elkholy Sherif , ElRashidy Mohamed , Munger Robert , Lasschuit Joost , Masselink Bram , McColl Allan , Boers Robin
Published: December 2021

As red zone management continues to be one of the most challenging risks on different types of drilling rigs, a Combined Operator Contractor Pilot was launched by Helin Data on a Maersk Drilling offshore rig contacted for bp Egypt that was operating in the Mediterranean for 10 years drilling and completing deep water HPHT wells aiming to integrate efficient drilling operations along with maximized safety.

The Red Zone Management Pilot system is composed of two main scopes; monitoring and detecting people and equipment on the drill floor using advanced video analytics technology and subsequently developing new technology to include alarmed movement of prime moving/hoisting drill floor equipment.

The Helin Data pilot system demonstrates full insight of both personnel and equipment movement in the red zone. In addition, the team looked to further reduce dropped objects related risks using hydraulic wireline winches. This was achieved by installing digital load cells on drill floor tuggers. Remote winch operation with load cells effectively mitigates overpull incidents and associated risks, while involving less persons in the red zone. The pilot project brought simple concepts together with successful results on raising situational awareness on the drill floor and reducing human error, the presentation focuses on the project's functionalities, main challenges and detailed system implementation phases.
Plastic Liners for Offshore Production Lines: A Cost Effective Alternative Solution to Corrosion Resistant Alloys?
Authors: Delaplace Thomas , Gouriou Morgan , Melot Denis
Published: December 2021

This paper presents the investigations performed by TotalEnergies and Saipem on the cost effectiveness potential of internal plastic lining for corrosion protection of offshore production lines. Objective was to better understand for a complete EPCI cost comparison the various parameters that could have a significant impact on the potential savings associated with the use of plastic lining instead of CRAs (Corrosion Resistant Alloys) for very corrosive production fluids such as sour gases.

An extensive cost comparison study between CRA lining and plastic lining for offshore production lines was performed considering sensitivity on several parameters: 3 pipe diameters, S-Lay, Reel-Lay and J-Lay installation, sensitivity to external thermal insulation requirements, mechanical and design requirements, to pipe length and fixed costs (technologies and vessels). A dedicated calculation tool for system design and cost assessment was built on purpose for this sensitivity study. Costs were assessed for the various cases, starting from pipe design, then assessing procurement costs, fabrication costs then installation costs with preliminary cycle time assessment. Project management and engineering costs have been considered to obtain comparative EPCI (as installed) cost assessments for the various study cases.

Plastic lining appears to be a cost-effective solution installed in J-Lay or S-Lay in addition to reeling (up to 45% of potential cost savings on installed line compared to CRA lining). The main driver for the cost savings is associated to the procurement of the pipes and associated lining, including pipe manufacturing. Some smaller savings can also be obtained from the offshore cycle times in J-Lay and S-Lay as the CRA welding add a significant operation time in comparison with standard CS welds. The fixed additional costs associated to the plastic lining (specific tooling for example) can be quickly amortized after a few kilometers thanks to the material cost savings. Integrating them as a company investment allows to unlock costs savings even for shorter lines. The thermal contribution of the plastic liner is also interesting regarding the overall pipe insulation design.

This study completes the works already performed by the industry on the offshore costs of plastic lining as it considers the whole EPCI CAPEX costs from the Contractor and Operator points of view and offshore experience. The study integrates the S-Lay and J-Lay installation methods (while previous studies mainly focused on Reel-Lay) and includes an extensive sensitivity study with various key parameters such as pipe sizes, pipe design requirements, material costs and offshore operation times to get a general overview of potential benefits associated with plastic linings for offshore production lines transporting corrosive fluids such as sour gases.
SE Abu Dhabi Aptian 5 Shuaiba System: Understanding a Heterogeneous Reservoir Trend
Authors: Whitcomb Nick , Seliem Abdulla , Marzen Rachel , Franco Bernardo Jose , Celentano Maria Agustina , Bose Sweta , Maldonado Pena Alejandra
Published: December 2021

The study area covers 1,300 km2 in southeastern Abu Dhabi and focuses on the Aptian (Apt.) 5 Upper Shuaiba progradational clinoform system. The Shuaiba Formation has been well-studied at the regional level, but with comparatively less focus on the Apt. 5 system. Studying depositional trends and shoal facies distributions within the Apt. 5 is critical for predicting reservoir presence and quality. Given the complexity of the Apt. 5 system, understanding the key controls over depositional environments, such as paleowind direction, is an important first step. This study combined regional context and geological understanding with previous studies to confirm existing clinoform interpretation, while also delineating four additional clinoform sequences using a reprocessed depth migrated 3-D seismic volume. Isochron maps were also used to group clinoforms into three packages distinguished by common morphologies possibly linked to their respective dominant reservoir facies. Preliminary observations suggest early clinoforms had more rudist build-ups, whereas the later clinoforms were dominated by narrow-shoal beaches.

Coalescing clinoform shoal patterns, observed in the spectral decomposition and amplitude extraction maps, likely result from a combination of Bab Basin morphology, longshore current, and dominant paleowind direction during the Early to Middle Cretaceous. Existing interpretations of dominant paleowind direction vary significantly, ranging between E-W and S-N. Interpretations from this study are most consistent with prevailing paleowind out of the east-southeast. The Arabian plate was likely near the equator around 10°S latitude during the Aptian, which supports the southeast wind hypothesis when considering modern Coriolis patterns. Consistent wind influence on shallow water shoal environments would have winnowed mud and increased the proportion of grain-dominated sediment preserved relative to lower energy areas. The grain-dominated facies appear to be reflected in amplitude responses around the coalescing clinoforms, and in the amplitude variations along strike coincident with clinoform edges. Reservoir presence and quality uncertainty can be reduced if these observations can be confirmed. An improved understanding of the Apt. 5 clinoform system in southeast Abu Dhabi, and possible influences on reservoir distribution and quality, will help develop a better understanding of risk for prospect maturation.
Enabling Safe and Efficient Well Plug & Abandonments Through Use of Rigless Technologies
Authors: Spuskanyuk Oleksandr , Haeberle David C , Baumert Brandon Max , King Brian Matthew , Hillier Benjamin T
Published: December 2021

The growing number of upcoming well abandonments has become an important driver to seek efficiencies in optimizing abandonment costs while establishing long term well integrity and complying with local regulatory requirements. With an increasing global inventory of Plug and Abandonment (P&A) candidates, Exxonmobil has been driven to look for the most reliable, safe, and cost-efficient P&A technologies. ExxonMobil's P&A guidelines are consistent with and often more stringent than the local regulatory requirements but are also achievable, at least in part, with rigless technologies, leading to a more cost-efficient approach while ensuring well integrity. The objective of this paper is to demonstrate the success of rigless abandonments and their benefits compared to rig-based solutions.

When developing a well abandonment plan, it is essential to consider a number of factors. These include local regulations, identification of zones to be isolated and suitable caprocks, and recognition of constraints including well history, conditions and uncertainties. Teams should begin with low cost operations without a rig if possible, estimate costs and effectiveness to achieve the barrier requirements, and evaluate batch operation opportunities for multi-well programs. ExxonMobil case studies are shown to help describe in detail how to make decisions about applicability of rigless abandonment options and how to properly execute such abandonments to achieve compliance with the barrier requirements.

It has been demonstrated that significant cost savings can be achieved by staging the abandonment program in a way that lower cost technologies are utilized during the early stages of well abandonment, starting with wireline where possible, followed by coiled tubing and finally by a pulling unit, as appropriate. P&A execution could be achieved without a rig in a majority of cases, including most offshore wells, with the need to use a rig only in special circumstances or phases of execution. It is important to note that the barrier placement and safety of rigless P&A execution will not be compromised, as compared to the rig-based P&As. Additional cost savings could be achieved by further optimizing P&A design at the well design stage, ensuring that there are no built-in limiters that would prevent rigless P&A execution at the end of well life.

Several case studies from ExxonMobil's global offshore experience demonstrate the feasibility and effectiveness of rigless P&A operations, with significant cost savings compared to rig-based P&As. It has been evident that rigless P&A choice is applicable to the variety of ExxonMobil's P&A projects of different complexities, with the same or superior quality of abandonment and safety record.
3D Visualization of Film Flow During Three-Phase Displacement in Water-Wet Rocks via Microtomography Method
Authors: W. Razak W. N. Adyani , Kechut Nor Idah , Andrews Edward , Krevor Samuel
Published: December 2021

Spatial image resolution has limited previous attempts to characterize the thin film flow of oil sandwiched in-between gas and water in a three-phase fluid system This paper describes how a systematically designed displacement experiment can produce imagery to define the film flow process in a 3D pore space of water-wet sandstone rocks. We image multiphase flow at the pore scale through three displacement experiments conducted on water-wet outcrop rock with variable spreading tendencies. The experiment has been formulated to observe the relationship between fluid spreading, phase saturations, and pore-scale displacement mechanisms.

We provide exhaustive evidence of the three-phase fluid configurations that serve as a proxy mechanism assisting the fluid displacement process in a three-phase system, which includes the oil sandwiches in-between water and gas, the flow of oil via clay fabrics, and the double-displacement process that generates oil and water film in 3D pore spaces. Further, we show evidence that the stable thin-oil film has enhanced the gas trapping mechanism in the water-wet rocks. We observed that the oil layer had covered the isolated and trapped gas blobs, enhancing their stability. As a result, the trapped gas in the positive and zero spreading systems is slightly higher than in the negative spreading system due to a stable oil film.

We analyze the Euler characteristic of the individual fluid phases and the interface pair of the fluids during waterflooding, gas injection, and chase water flooding. The comparison of the Euler characteristic for the connected and disconnected fluid phases between three different spreading systems (i.e., positive, zero, and negative) shows that the oil layer's connectivity is highest in the positive spreading system and lowest in the negative spreading system. The oil layer in the positive spreading system is also thicker than in the negative spreading system.
Doing the Right Things Through Operator Proactive Monitoring
Authors: Khoori Ziad , Novendri Ivan
Published: December 2021

Operator Proactive Monitoring is one of the critical paths to Ensure Safe Production. The objective is to ensure that facilities are proactively monitored to retain the best possible level of situational awareness. It is achieved by monitoring and control the unit and equipment to avoid exceeding a safe limit while meeting all operational and business targets. It promotes early detection & appropriate intervention to an arising abnormal situation. Operator Proactive Monitoring covers a wide range of activities from a control room and field operation.

ADNOC Gas Processing, in line with the digital transformation program, has enterprise assets/equipment through implementing Operator Proactive Monitoring for control room and field operator. Operator rounds play an essential role in improving plant reliability and safety.

This research aims to measure the effectiveness of the Operator Proactive Monitoring by the Ruwais NGL Operation division at ADNOC Gas Processing.

By "doing the right thing," Operator Proactive Monitoring effectively supports and improves process safety culture in the operation business of Ruwais Plant division of ADNOC Gas Processing.
Data Analytics into Hydraulic Modelling for Better Understanding of Well/Surface Network Limits, Proactively Identify Challenges and, Provide Solutions for Improved System Performance in the Greater Burgan Field
Authors: Dashti Qasem , Matar Saad , Abdulrazzaq Hanan , Al-Shammari Nouf , Franco Francy , Haryanto Elin , Zhang Michael Q. , Prakash Roshan , Bolanos Nelson , Ibrahim Muhammad , Afifi Mostafa
Published: December 2021

A network modeling campaign for 15 surface gathering centers involving more than 1800 completion strings has helped to lay out different risks on the existing surface pipeline network facility and improved the screening of different business and action plans for the South East Kuwait (SEK) asset of Kuwait Oil Company.

Well and network hydraulic models were created and calibrated to support engineers from field development, planning, and operations teams in evaluating the hydraulics of the production system for the identification of flow assurance problems and system optimization opportunities. Steady-state hydraulic models allowed the analysis of the integrated wells and surface network under multiple operational scenarios, providing an important input to improve the planning and decision-making process.

The focus of this study was not only in obtaining an accurate representation of the physical dimension of well and surface network elements, but also in creating a tool that includes standard analytical workflows able to evaluate wells and surface network behavior, thus useful to provide insightful predictive capability and answering the business needs on maintaining oil production and controlling unwanted fluids such as water and gas. For this reason, the model needs to be flexible enough in covering different network operating conditions.

With the hydraulic models, the evaluation and diagnosis of the asset for operational problems at well and network level will be faster and more effective, providing reliable solutions in the short- and long-terms. The hydraulic models enable engineers to investigate multiple scenarios to identify constraints and improve the operations performance and the planning process in SEK, with a focus on optimal operational parameters to establish effective wells drawdown, evaluation of artificial lifting requirements, optimal well segregation on gathering centers headers, identification of flow assurance problems and supporting production forecasts to ensure effective production management.
Molecular Simulation of Methane Sorption onto Kerogen Surface of Shale in Presence of Surfactant
Authors: Abduelah Hesham , Negash Berihun Mamo , Kim Keong Boon , Padmanabhan Eswaran , Arif Muhammad , Metwaly Ahmed Reda , Keshavarz Alireza , Iglauer Stefan
Published: December 2021

Shale reservoirs, despite having abundance in hydrocarbon storage, offer significant challenges in terms of understanding the pore-scale and reservoir-scale phenomenon. Typically, hydraulic fracturing treatment is implemented to improve hydrocarbon productivity through the injection of fracturing fluid to induce the breakdown of the formation to create fractures, hence allowing a flow conduit for hydrocarbon to be produced at a higher flow rate of oil and/or gas. In this work, molecular dynamics (MD) simulation using GROMACS were utilized to create a 3D model comprised of methane (CH4), surfactant and graphite. Surfactant, as represented by the cationic cetyl trimethyl ammonium bromide (CTAB) was added along with water to represent water-based visco-elastic surfactant (VES) as an additive to reduce the surface tension of hydrocarbon to shale (represented by graphene). A realistic molecular model was created to examine the interaction of CTAB towards the adsorption pattern of methane onto graphene, in order to reveal the displacement efficiency of methane after wettability modification due to the effect of surfactant on the graphene on a nanoscale. The findings suggest that addition of CTAB as surfactant may enhance the production of methane though the reduction of IFT and adsorption capability of methane to the wall of shale. The result yielded consistent trends, where methane's tendency to stick to the adsorption site (at approximately 1.5 nm from the center of the system) was reduced and more methane molecules were accumulated at the center of the pore space. This study has uncovered the adsorption process and the effect of CTAB in altering the sorption behavior of methane towards shale. This would contribute to the enhancement of long-term shale gas production by providing more information on salinity and pressure sensitivity, enabling extraction to be done at a lower cost.
Produced Water Reuse for Drilling and Completion Fluids Using Ion Exchange Resins
Authors: Dossary Hind S. , Alghunaimi Fahd I. , Choi Young C.
Published: December 2021

Produced water is considered one of the largest by volume waste streams and one of the most challenging effluents in the oil and gas industry. This is due to the variety of contaminants that make up produce water. A variety of treatment methods have been studied and implemented. These methods aim to reduce the hydrocarbon content and the number of contaminants in produced water to meet the disposal, reuse, and environmental regulations. These contaminants can include dispersed oil droplets, suspended solids, dissolved solids, heavy metals, and other production chemicals. Some of those contaminates have value and can be a commodity in different applications such as bromine (Br). Bromine ions can be used to form calcium bromide, which is considered one of the most effective drilling agents and is used extensively in drilling and completion operations. This paper aims to highlight the utilization and the new extraction method of bromide ions from produced water to form calcium bromide (CaBr2). The conventional preparation of calcium-bromide drilling and completion fluids involves adding solid calcium-bromide salts to the water, which can be relatively expensive. Another method can involve the handling of strong oxidants and toxic gas to form solid calcium bromide. The novel method outlined in this paper is a cost-effective and environmentally friendly way of generating calcium bromide from produced water. The method includes processing the produced water to recover bromide ions. This is done by first passing the produced water through a resin bed, including bromine-specific ion exchange resin, where the bromide ions will adsorb/absorb onto the resin, as shown in Figure-1. The second step involves regenerating the resin with regenerant having calcium cations and water to form calcium bromide. The final stage is generating the calcium bromide in the water from the bed of resin by introducing concentrated CaCl2, forming a concentrated solution of water and calcium bromide. The developed solution will be further processed to give drilling and completion fluids. This novel method constitutes a good example of produced water utilization in different applications to minimize waste and reduce the costs of forming highly consumable materials.
Step Change Transformation of Legacy Rigs to Autonomous Drilling Rigs
Authors: Ziatdinov Sergey , Thomas Philip Titto
Published: December 2021

During the past decade, drilling automation systems have been an attractive target for a lot of operating and drilling companies. Despite progress in automation in various industries, like mining and downstream, the drilling industry has lagged far behind in the real application of autonomous technologies implementation. This can be attributed to harsh environment, high level of uncertainty in input data, and that majority of stock is legacy drilling rigs, resulting in capital intensive implementations. In the past years there have been several attempts to create fully automated rigs, that includes surface automation and drilling automation. Such solutions are very attractive, because they allow people to move out of hazardous zones and, at the same time, improve performance. However, the main deficiency of such an approach is the very high capital investment required for development of highly bespoke rigs (Slagmulder 2016). And in the current business environment, with high volatility in oil and gas prices, plus the huge negative effect of the Covid-19 crisis on the world's economic situation, it would be hard to imagine that there are a lot of companies willing to make such a risky investment. In addition to this, due to the lack of demand, the market is full of relatively new, high-performance rigs.

Taking all these into account, the obvious question is whether it makes sense to invest money and time into the development of drilling automation. The answer should be yes, for three substantial reasons:Automation improves personal safety, by moving people out of danger zones;Automation improves process safety, by transferring execution from person to machine, which reduces the risk of human error;Automation improves efficiency by bringing consistency to drilling and through the use of self-learning algorithms, which allow machines to drill each successive well better than the previous.

This paper will not look into surface automation, such as pipe-handling, chemical and mud handling on site. The paper is focused on the subsurface, namely on the drilling automation process, the challenges that need to be overcome to deploy a vendor agnostic system on a majority of existing rigs.

A vendor agnostic system is a modification of an operator's autonomous drilling system (Rassenfoss 2011), designed to use existing rigs, BHAs, and have minimum footprint on the rigs for operational use. A vendor agnostic system will increase adoption of automated technologies and further drive improvements in operational and business performance
The Geochemical Survey Methods for Optimization of Oil Field Development
Authors: Sergeevna Shipaeva Maria , Karlovich Nurgaliev Danis , Anatolevich Sudakov Vladislav , Albertovich Shakirov Artur , Abuzarovich Lutfullin Azat , Galievich Ganiev Bulat , Ilfatovich Minikhairov Lenar
Published: December 2021

The paper considers issues of determining the direction of filtration for oil deposits by means of complex study of the geochemical composition of formation fluids and the dynamics of bottomhole pressure and flow rates, and further use of this information in geological and reservoir simulation models. This integrated technology is not expensive and makes it possible to identify geological uncertainties in the reservoir for intelligent management of development processes, such as waterflooding optimization, reservoir simulation models improvement, water cut source definition, etc. Improving the reliability of information about the reservoir and the presented fluids is undoubtedly relevant and significant task. To solve this problem, fluid samples were taken and complex studies of the composition of the produced water was carried out, including the determination of hydrogen and oxygen isotopes and element composition. The authors note that the isotopic composition of formation waters for a number of wells differs from the analogical parameters for injected water, which is probably associated with the area of ​​uneven reservoir distribution and the existence of a stagnant undrained zone. The result of the calculations is an estimate of the impact coefficient of the injected water on the water composition in the surrounding producer wells. In addition to this, the work included the analysis of the dynamics of fluid flow rate, oil flow rate, bottomhole and reservoir pressures, the influence of injection on the pressure in the drainage area of ​​producer wells. Basing on the results obtained the recommendations were given for changing the injection patterns as it is noted that a number of wells are not affected by injection. Recommendations have been developed for carrying out workovers in order to prevent a decrease in pressure and an increase in oil production.
Scale Mitigation for Field Implementation of Alkaline-Surfactant-Polymer ASP Flooding in a Heterogeneous High Temperature Carbonate Reservoir with High Divalent Cation Concentration in Formation Water
Authors: Al Murayri Mohammed T. , Sulaiman Dawood S. , Al-Kharji Anfal , Al Kabani Munther , Sorbie Ken S. , Ness Giulia , Pitts Malcolm J. , Salehi Mehdi
Published: December 2021

An alkaline-surfactant-polymer (ASP) pilot in a regular five spot well pattern is underway in the Sabriyah Mauddud (SAMA) reservoir in Kuwait. High divalent cation concentrations in formation water and high carbonate concentration of the ASP formulation makes the formation of calcite scale a concern. The main objective of this study is to investigate the severity of the calcium carbonate (CaCO3) scaling issues in the central producer in pursuit of a risk mitigation strategy to treat the potential scale deposition and reduce the flow assurance challenges. Calcite scaling risk in terms of Saturation Ratio (SR) and scale mass (in mg/L of produced water) in the pilot producer is potentially very severe and the probability of forming calcium carbonate scale at the production well is high. Produced Ca2+ concentration is high (> 800 mg/l), which makes the equilibrated calcite SR severe (> 500) and results in significant amount of scale mass precipitation. Different flooding strategies were modelled to evaluate a variety of flood design options to mitigate scale risks (varying slug size, Na2CO3 concentration, and volume of softened pre-flush brine), with marginal impact on scale formation. When the high permeability contrast of the different layers is reduced (to mimic gel injection), calcite SR and precipitated scale mass is significantly reduced to manageable levels. The option of injecting a weak acid in the production well downhole can suppress most of the expected calcite scale through reduction of the brine pH in the produced fluid stream for the ASP flood. Weak acid concentrations in the range of 4,000 to 5,000 mg/l are forecast to mitigate scale formation.
The Impact of Sulfate Level Reduction on Seawater Injection Economics: Using Sulfate Scale Precipitation Kinetics to Our Advantage
Authors: Abdallah Dalia Salem , Grutters Mark , Stalker Robert , Hutchison Rob , Stewart Christopher , Wilson Samantha C.
Published: December 2021

ADNOC Onshore plans to use seawater as alternative to aquifer water, its source of injection water for over 40 years. However, using seawater for injection introduces a sulfate scaling risk due to incompatibility with formation water. Sulfate in the seawater and cations in the formation water (Ca, Sr) are likely to precipitate, causing scaling and related flow assurance problems and formation damage. Sulfate can be removed from the injection water by means of desulfation, but sulfate removal to well below its scaling concentration is CAPEX intensive and negatively impacts seawater flooding economics. In this paper, the economic benefits of partial sulfate reduction are evaluated, by finding a balance between controllable scaling and costs for inhibition and sulfate removal.
Leadership and Managerial Decision-Making in an AI-Enabled Oil and Gas Industry
Authors: Agbaji Armstrong Lee
Published: December 2021

The Age of AI is defining a new set of challenges for leaders and the integration of digitalization and analytics into management decision-making is now a strategic priority for the oil industry. The fundamental challenge currently confronting the industry is to find leaders who can lead in the digital age. As the industry grapples with the AI revolution, pressure is mounting on leaders to react swiftly to the disruption that comes in its wake. Leadership and management methodologies currently employed by most organizations will not suffice in the digital age because leadership in this new age requires a different set of skills and organizational alignment. Yet, many organizations continue to struggle to put leaders in place with the knowledge and expertise to take on the challenges of leading in an AI-enabled world.

This paper addresses the challenges and responsibilities that the AI revolution presents to oil industry leaders and provides practical insights to confront them. It details the concept of ambidexterity and why it is difficult for oil industry managers to achieve. It also outlines what it takes to implement an ambidextrous strategy in the industry and presents a framework for leaders as they drive transformation and explore strategies that will shape the industry's transition to net-zero energy. With social media now shaping business decision-making, the paper also discusses its impact and presents a unique approach for leadership to be strategically positioned to reconfigure their organizations to ensure they survive and thrive in the social age.

Artificial Intelligence in the oil industry is not just about managing operations and reducing operating cost. It is also about developing a completely new way of doing business. Leadership in the digital age will be held accountable to a different standard. They would not only be judged by their ability to drive strategy and deliver financial results; they would also be judged on their ability to leverage AI resources and drive deep analytics mindset across their organization, while dealing with energy transition and social media. The workforce of the future will be dominated by technologically sophisticated people connected to multiple platforms. Managing this workforce will require a new kind of managerial wisdom.

The big gains from digital transformation will not be realized unless industry executives rethink the criteria with which leadership and management success is judged. Becoming a transformational digital leader requires the ability to define a strategic vision for transformation, understand the promise and peril of social media, cultivate employees to succeed with AI, and use AI responsibly. The future belongs to leaders with these abilities and capabilities.
Considerations and challenges of qualifying a metal powder bed fusion 3D printing process
Authors: Malkawi Ameen , Ganti Satya , Aleid Zahra , Sharrofna Hussain , Minhas Naeem , Barta Nicholas
Published: December 2021

This paper discusses the considerations taken into account before printing additively manufactured (AM) parts, the challenges faced during the printing process, and the standards, methods, and techniques by which the parts are qualified for use. We discuss the four major categories of AM powder bed fusion (PBF) qualification process namely feedstock qualification, machine and process qualification, material qualification, and part qualification. We discuss what each of these qualification processes entails and provide suggestions where appropriate.

In this paper, the activity and direction within the international standards community to help drive the widespread adoption of AM technology in various industries is also discussed.
A Core Flood Test-Program Performed with a Pilot-Skid to Quantify the Permeability Decline Induced by Real Treated Produced Waters Also Containing Degraded Polymer or Not
Authors: Oughanem Rezki , Gumpenberger Thomas , Boero-Rollo Jean Grégoire , Suleiman Scherwan , Ochi Jalel , Chiotoroiu Maria-Magdalena , Hannes Abdalla
Published: December 2021

A water treatment pilot skid called WaOω has been developed by TotalEnergies to test the efficiency of the centrifugation technology in treating the produced water containing back produced polymer. In case of success, this technology would be implemented on field and the water quality targeted by the technology must allow re-injecting the treated produced water in matrix flow regime for pressure maintain and sweep efficiency. The same interest was expressed by OMV and a partnership project has been built. It was also agreed that OMV builds a second pilot skid called PRT that allows carrying out core flood tests onsite to assess the formation damage and related permeability decline that could be induced by the treated produced water.

Both pilot skids have been implemented, connected to each other, and tested during more than one year on the OMV's Matzen oil field nearby Vienna where degraded polymer is already back produced by wells and present in the produced water.

More than seventy core flooding tests have been performed in different centrifugation conditions in terms of speed and water qualities, some of them on high permeable sand packs representing the field targeted by TotalEnergies and some others on consolidated sandstone samples of lower permeability representing OMV reservoirs. The effect of adding fresh polymer to the treated produced water for EOR purposes has also been investigated. Some complementary core flood tests have also been performed in TotalEnergies labs using reconstituted sand packs and produced waters with and without polymer to understand the contribution of the degraded polymer alone, the produced water quality alone and both to understand the formation damage and some uncommon results observed with the PRT pilot skid.

Core flood tests data often obtained on long injection periods revealed of a high quality, reliable and reproducible. They also showed that even if centrifugation seems to be a good technology, the very clean and transparent water that it delivered induced surprisingly some core permeability declines the origin of which would be discussed in this paper. However, it was clearly established that the presence of degraded polymer has a cleaning effect and limits the formation damage induced by the produced water injected on cores if the Total Suspended Solids in the treated water remains at an acceptable level. Adding fresh polymers limited even more the formation damage because their cleaning effect is more pronounced than with degraded polymer.