bluuebunny/crossref_metadata_2025_split huggingface dataset:
High Rate Sour Gas Wells' Solids Free Clean Out
Authors: Ahmari Abdulrahman S. , Uzcategui Elio A. , Alsyed Samih M. , Ghamdi Abdulrahman A. 
Published: May 2012

Abstract
Saudi Arabia's first offshore high rate dry gas field has an over pressured reservoir. Successful pressure control during drilling required the use of barite in the water based drilling mud. Barite is very abrasive and is insoluble in any acid or solvent. Any barite left in the reservoir due to mud losses has to be produced back to surface after completing the wells. This cleanup is crucial for the safety and longevity of permanent facilities, especially when high rate gas wells are involved; due to the high rate of impact of any solids that may be produced with the gas. It is also critical to design the cleanup job carefully to ensure proper equipment and safety measures are taken to avoid washouts and related safety hazards.
To ensure solids free production from day one, a procedure was implemented and successfully executed during the development of this first offshore high rate high-pressure sour gas field. This was achieved by using the rig as a main support and complementing the safety with the incorporation of the selected Solids Management System. In addition to the proper equipment, a detailed cleanup procedure, which covered systematic production ramp up and defined solids free criteria, was implemented. The added value and safety from having the rig on location during well cleanups is the expertise to kill the well in case of any well control problems. So far, this well cleanup setup and program has been implemented on 14 wells on three platforms with minor erosion and no safety issues. One platform with five wells is already producing and is flowing trouble free. This paper will describe the details of the setup of the rig facilities to clean these barite laden fluids from the wells, and the solids control equipment used and the cleanup procedure.
Work Execution Data is the Key to Managing Day to Day Frontline Operational Risk
Authors: Lehmann Scott , Wilson Peter 
Published: May 2012

Abstract
Despite the efforts to improve frontline work execution procedures and practices as a part of HSEQ and Sustainable Development, the industry's efforts often result in better rulebooks, best practices and more robust procedures yet no noticeable decrease in the number of HiPO's, incidents and fatalities. Many of the existing control systems, like permit to work, only manage each job or task as a single unrelated point of activity and provide us with no line of sight on the potential cumulative risk of frontline work. Furthermore, typically the industry is managing work execution as one of its most important business processes on paper. Paper systems provide no data and without data there is no effective and scalable manner to manage day to day frontline operational risk.
Technology can play an integral role in guiding and structuring decision making by ensuring safety rules, best practices and lessons learned are deeply embedded into operational processes for frontline workers and management. In this way, risk controls and guidance can take shape outside of the ‘rule book’ and become an integral part of routine operations. The work execution process can be captured thus providing a window into how well frontline operational risks are being managed.
Using a customer data set of frontline work execution data and a copy of their incident and accident information, we can demonstrate how an organization, through the use of technology, can use planned and actual real time job and hazard data to effectively manage their operational risk and head off potential incidents before they occur. By showing what issuers and approvers of frontline work would have seen in terms of the actual cumulative risk score for actual frontline planned work, we will be able to demonstrate they would have had the visibility to know where to act and when thus potentially avoiding or minimizing the scope of an incident.
Addressing Work Execution with the right combination of people, process and technology can establish line of sight on the potential cumulative risk of frontline work in order to provide insight and oversight to make better decisions around operational risk in order to improve safe, reliable and compliant operations. Managers can now exercise oversight and use the data to not only demonstrate compliance, but build the foundation for continually improving operational standards and performance.
Utilization of MDEA Selectivity to Manage the Operation of Sulphur Recovery Plant during Mechanical Failure in Tail Gas Line
Authors: Al-Kubaisi E.. , Shafah J.. , Al-Mahmoud G.. 
Published: May 2012

Abstract
The Modified Claus Process is widely used to recover sulphur in the natural gas processing industry1. It consists of two defined conversion stages: thermal and catalytic. The non-converted acid gas is sent, along with the tail gas, to the incineration furnace. This is a typical arrangement to prevent the release of toxic gases.
Qatar Petroleum operates an NGL complex with a Sulphur Recovery Unit (SRU) that uses the Modified Claus Process. In July 2011, a leak developed in an expandable pipe segment that allowed toxic gas to be released.
The incineration furnace's flue gas stack is designed to cause negative pressure at the incineration furnace. This is made possible by having it open to atmosphere through its effluent stack. Negative pressure is always met at reduced throughput. Thus, reducing the SRU throughput would prevent toxic gas leakage. The downside of the throughput reduction is that the excess acid gas would be flared.
Gas Operations, in a unique approach, utilized the inherited selectivity characteristics of MDEA solution, to optimize the overall operation. The optimization was done in a way that would affect the quantity and composition of the acid gas. This meant that we could operate the SRU in a safe manner with no environmental impact.
A detailed description of what we did to minimize Acid Gas flaring, without violating the AGRU product specs and without further deterioration of the leaking expansion bellow, are covered below. We also describe the benefits realized.
Where Process Safety Must Move
Authors: Matthews Teg 
Published: May 2012

Abstract
Process safety has long embodied the adage, "If you always do what you've always done, you'll always get what you've always got." Despite the development of sophisticated technical and management systems in recent decades, major catastrophic incidents continue to occur. Study of these events show us that the technical failures that led to these events were in fact enabled by organizational failures. Yet process safety systems too often exist in isolation from the wider organization, and indeed from other safety activities themselves. In order to achieve next-level improvement, catastrophic event prevention must move from its position of sole (or disproportionate) focus on the safety technical and management systems to a comprehensive focus that encompasses the broader elements of organizational safety as well. This talk presents the problem facing process safety practitioners today and outlines seven principles that can guide leaders both in aligning the organization to support process safety functioning and in assuring the integrity of process safety systems themselves.
Well Structure Optimization in Complex Wells for High Permeability Reservoirs
Authors: Al Ramis Hussain , AlOthman Khalid , AlYami Abdullah 
Published: May 2012

Abstract
The objective of drilling long horizontal wells and maximum number of laterals is to achieve maximum production rate. Reservoir contact of more than 5 km was drilled successfully through intelligent laterals (up to 5 laterals) that can be controlled from the surface. Currently there is a growing tendency of drilling higher number of laterals in the industry to maximize the production rate. The objective of this study is to evaluate the possibility of achieving this growing multilateral completion through two milestones.
The first milestone of this study is the effectiveness and well designoptimization for several cases with critical parameters such as reservoir permeability, wellbore diameter, skin factor, reservoir drawdown, and well tubular roughness.
The second milestone is to address the optimal maximum reservoir exposure in high permeability reservoirs (200-800 md) for high lateral-number in multilateral wells.
The methodology conducted in this study consists of two main parts, reservoir/wellbore coupling model for production rate calculation from individual lateral and then pressure drop in building sections. Single-phase flow was used to investigate different parameters affecting lateral flow rate. Two-phase flow was used in pipe flow to investigate the possibility of drilling more than 10 laterals.
The study shows how pressure at the junction can be used to determine the optimum lateral length as a starting point when designing multilateral wells. The parameters analyzed include viscosity of reservoir fluids, well diameters and number of laterals. The pressure drop due to friction lead to different flow rates at the surface regardless how strong the inflow performance is. The effect of roughness on pressure drop is minimal and only becomes significant at lateral length more than 20000 ft. The characteristics of flow in building section and junction are the key for a well having high number of laterals.
Optimized Drilling by Improved Well Control Using MPD in Narrow Pressure Window
Authors: Mathew Sangeeth George , Nasr G. G. 
Published: May 2012

Abstract
Towards the later part of the 20thcentury, the oil industry has been looking for more safer and beneficial drilling methods, especially in deep waters. The high well/field costs pushed the need for attractive technologies which would optimize drilling. Also ever since the catastrophic events of April 2010 in the Gulf of Mexico, the oil industry has been constantly scrutinized for the health and safety standards or rather the lack of it. The consequences of the blowout highlighted the need for improved kick detection and well control. In deepwater wells, there exists a narrow window between the fracture pressure and the pore pressure. This narrow margin poses a safety hazard both for the well and the crew operating on it. Drilling in these sort of fields require distinctive methodologies to achieve both objectives of safe and optimized drilling.
Thus one such method which would optimize drilling and improve well control is Managed Pressure Drilling (MPD). This has been defined as "an adaptive drilling process to accurately control the annular pressure profile throughout the well". This technique would create a pressure profile in the well to be within tolerance and close to the boundaries or limits controlled by the pore and fracture pressure.
For the understanding of kick detection, well control and circulation when MPD is being employed, a hypothetical well data with a narrow pressure window is selected and a kick is simulated to be controlled using MPD. The pump rate & mud density is studied and kick detection, well control and circulation is analyzed and interpreted. Obviously with the usage of the MPD tools and equipments during drilling, there would be a difference from conventional kick detection, which could probably be enhanced well control. MPD would thus, be able to properly manage any influxes from the formations thereby protecting the system and structure above and have a telling effect on the Non Productive Time (NPT).
This paper aim to differentiate the conventional and MPD method of kick circulation based on simulations of lost time and lost circulation. By obtaining the desired result, we can justify the usage of MPD in a narrow pressure window field/reservoir for improved kick detection, control and circulation and thus drilling optimization.
Seawater Injection into Clastic Formations: Formation Damage Investigation Using Simulation and Coreflood Studies
Authors: Al-Mohammad Abdullah M. , Al-Khaldi Mohammad H. , Al-Yami Ibrahim S. 
Published: May 2012

Abstract
Waterflooding in different reservoirs for pressure maintenance and recovering more oil is a well established practice in the oil industry. Many research studies have shown that the success of any waterflooding process is mainly dependent on both physicochemical (fluid-rock) and geochemical (fluid-fluid) interactions. These interactions have been extensively investigated during seawater injection into carbonate formations. However, the rock/seawater chemical interactions are completely different in sandstone than in carbonate formations, due to different rock mineralogy. Therefore, the main objective of this paper is to investigate both the potential physicochemical and geochemical formation damage mechanisms that might occur during injection of seawater into a central Arabia sandstone formation.
Scaling potential due to seawater-produced brine chemical interactions was investigated at an average reservoir temperature of 186°F, based on the Pitzer theory of electrolytes. In addition to the prediction data, laboratory compatibility tests were conducted to investigate the scaling potential in different seawater/produced brine mixtures at reservoir temperature. Since this sandstone formation contained different clays, such as illite and smectite, the clay swelling and fines migration tendency was explored using coreflood setup and zeta potential technique.
The saturation index (SI) of different scales, such as calcium carbonate and calcium sulfate, was found to be mainly dependent on a seawater/produced brine mixing ratio. Additionally, it was found that scaling did not occur in supersaturated mixtures of seawater, aquifer water and produced brine, which indicated that there is a critical SI for the scaling onset. The zeta potential for different formation rocks was determined for sweater, aquifer and produced brine. It was nearly zero when using only seawater. One of the major findings of this study is that the presence of sulfate ions caused clay particles to migrate even in high total dissolved solid (TDS) seawater of nearly 55,000 ppm.
Leveraging Technology Infrastructure and Experience to Enable Upstream Asset Optimization
Authors: Killian Keith E. , Jones Chris G. , Wiemers Suzan , Dubose Larry W. 
Published: May 2012

Abstract
Applying digital technology in the upstream introduces new equipment and applications that have the potential to transform asset management and optimization processes. Technology selection, delivery, sustainment and most importantly, business integration are key factors in making effective digital technology investments and realizing their full value. Leveraging the significant experience and synergies in ExxonMobil's* Information Technology organization and downstream has been recognized as an opportunity in the upstream to facilitate quicker technology deployment and effective, efficient sustainment. Aligning with business priorities, decisions on digital technology enablers are linked with relevant upstream best practices to facilitate integration with asset management work processes.
This paper will focus on ExxonMobil's approach with leveraging our corporate infrastructure and experience to deliver targeted upstream capabilities related to facilities, process and equipment surveillance and optimization, as well as how it enables further technology applications in advanced analytics and advanced process control.
A Unified Approach to Well Integrity Evaluation Led to Better Decision Making for Workovers in Mature Wells in the Waddell Ranch, West Texas
Authors: Babaniyazov A.. , Clayton R.. , Sykes-Bookhammer D.. , Walker R.. , Amezcua J.. 
Published: May 2012

AbstractThe often referenced Norwegian standard D-0101 describes well integrity as the "application of technical, operational and organizational solutions to reduce the risk of uncontrolled release of formation fluids throughout the life cycle of a well". Well integrity can therefore be considered in terms of the structural soundness of the well, its casing, cement and wellhead; and how it reduces the risk of the uncontrolled flow of formation fluids to other formations or surface.Well integrity is a critical issue when working over and recompleting mature wells. This paper describes common integrity issues and develops a workflow for managing well integrity information during the design, execution, and evaluation of workover operations.It was found that no one measurement can give a complete well integrity analysis; instead a unified systematic approach considering a variety of measurements will lead to successful, economical, and well executed workovers.There is a great deal of value in obtaining certainty about the status of a wellbore from a clear logging and testing regime. The type of logging package will depend on the economics of the recompletion campaign, but the cost of logging operations pales in comparison to a lost hydraulic fracture or series of expensive squeezes.The evaluation and quantification of workover rates, reserves and economics in this field are not within the scope of this paper, and will not be addressed here.
Design Considerations for Isolating Gas-Hydrate-Bearing Zones in Deepwater Environments
Authors: PKS Sairam , Patil Rahul , Patil Sandip 
Published: May 2012

AbstractGas hydrates are known to occur in deepwater environments (low-temperature and high-pressure) at various locations across the globe. When they occur close to the sea bed, hydrates present challenges to drilling, completing, and producing in deepwater applications. Additionally, many operators now consider these as a potential resource when they occur deeper within the earth, and there is increased focus on feasibly producing methane from gas hydrates. Safety, environmental impact, and economic viability are the foremost challenges faced by the upstream oil and gas community to unleash the potential that these unconventional reserves hold for the future.Isolating the gas-hydrate-bearing zones by means of effective annular wellbore sealants is the prime factor that will contribute to the success of gas-hydrate campaigns. This paper addresses the current zonal isolation challenges likely to be encountered from the time drilling operation is completed until the plug and abandonment process is finished. With the considered lifecycle, a sealant system selection criteria based on commercially available technologies is proposed. While industry research on this front continues to progress, a holistic approach to designing a zonal isolation program to address the foreseeable challenges of unconsolidated formations, drilling-fluid removal in washouts, annular-sealant placement, battling lost circulation, prevention of hydrate destabilization, formation-fluid influx during the setting process, achieving good mechanical properties at low temperatures, and maintaining long-term sealing integrity throughout the life of the well is discussed and evaluated.The design approach involves (1) preliminary engineering sensitivity analysis to judge the effect of dominant parameters on sealant system design, (2) selection of commercially available, fit-for-purpose materials and laboratory testing, and (3) validation by means of confirmatory analyses. The approach presented is an incremental effort to help operators and industry researchers increase the productivity of gas-hydrate-bearing wells.
Flow Assurance In Oil Systems: On the Role And Impact Of Naphthenic Acids
Authors: Shepherd Andrew G. , Dijk Menno van , Koot Wouter , Dubey Sheila , Poteau Sandrine , Zabaras George , Grutters Mark 
Published: May 2012

Abstract
This paper presents an overview of the different flow assurance issues associated with naphthenic acids. In field development projects a good understanding of naphthenic acid phase behavior is essential to avoid unplanned plant changes and deferment. Good data on naphthenic acid content and speciation is obtained by using a representative sample. Basic measurements (e.g. TAN) are not sufficient to obtain a detailed understanding of the flow assurance issues regarding a particular crude oil. Infrared spectroscopy and mass spectrometry, high and low resolution, are the preferred tools for analysis of crude oils. The target naphthenic acid species, e.g. ARN or fatty acids will dictate the best suited method selected for analysis. Geochemical analysis of crude oils has helped to highlight some common features which can be used for prediction purposes. For bound soap scale-forming crude oils, a large amount of complexed acids result in emulsions which are difficult to break. Chemical treatments are needed and these should be identified early in the project stages. For soap scale-forming crude oils chemical treatment requires in depth analysis of topsides equipment and impact on existing chemical portfolio. Surveillance of soap scale-forming crude oils is possible using readily available equipment. For soap emulsion-forming crude oils, paraffin precipitation adds to the stability of the emulsion formed. Chemical treatment and heat is required for best results. Use of stock tank sample properties can be used for predictions regarding the type of naphthenic acid issue to be expected for particular crude oil sets.
Utilizing Production Logging in a Complex Completion to Enhance Productivity through Comprehensive Production Profiling, Workover Planning, and Recompletion
Authors: Gupta Shilpi , Sinha Ravi , Kumar Ajit , Pandey Arun , Ogra Konark , Verma Vibhor , Bisht P.. , Hinge P. P. 
Published: May 2012

Abstract
Production logging (PL) has long been in use in the industry for evaluating the well performance for making strategic decisions. However, understanding the production profiles is challenging in complicated flow regimes and complex wellbore completions. To increase productivity in underperforming sick wells, electrical submersible pumps (ESPs) are generally effective options if planned and installed judiciously. This unique case study validates the application of production logging in planning and executing workover operations and by diagnosing the issues for suboptimal production performance of an ESP completed well.
Located in XYZ field of Mumbai offshore in India, Well G has been in production since October 2006, predominantly producing at the rate of 900 barrels of oil per day (BOPD) with 10% water cut (WC). After producing for 2 years, well production declined significantly to 600 BOPD. PL data were used efficiently to increase productivity at three different stages during the life of the well. In the first stage, PL played a key role in mapping the zonal production profile. On the basis of these data, an acid job was suggested, which increased production by 300 BOPD. In the second stage, when the production rate again declined to 600 BOPD within a year, PL played a key role in defining perforation and re-perforation strategy by identifying the silent zones and helping to plan ESP installation when the well was incapable of lifting fluids to surface. This led to an increase of only 50 BOPD as compared to the expected increase of 600 BOPD. During the third stage, PL combined with a Y-tool was instrumental in diagnosing a mismatch between ESP design capacity and reduced reservoir deliverability, which was the key reason for the unexpected underproduction. On the basis of the diagnosis, an acid job was suggested to increase well deliverability. Following the acid job, production increased by almost 75% to 1034 BOPD without changing and damaging the ESP.
This case study is of interest to plan workover operations and to diagnose production problems using PL to optimize production in ESP completed wells with changing reservoir productivity.