bluuebunny/crossref_metadata_2025_split huggingface dataset:
Downhole Analysis and Laboratory Analysis, Key Complementary Techniques for a Comprehensive and Effective Fluid Characterization
Authors: Al-Sabea S. H. , Al-Rushaid M. A. , Mohamed A. A. , Bouchet F. D. , Harami K. K. , Al-Khabbaz M. J. , Slimani K. M. , Jamal S. , Ayyad H. A. , Aguilera P. R. 
Published: December 2013

Abstract
Downhole sampling and laboratory analysis are key complementary techniques offering a step change in fluid characterization. It is generally accepted that fluids in the reservoir are in chemical equilibrium. However this assertion, although convenient, is often invalid, for several reasons from source variations, due to in-reservoir reaction, degradation or precipitation. In a large majority of cases many of these phenomena are difficult to appreciate, because the techniques used for fluid sampling often lack the pin-point acquisition accuracy (geographical, depth and time) required to provide the information at a level of accuracy sufficient to detect subtle variations. Instead only a mixture of different oil is captured providing "averaged" oil composition and characteristics, whereas the reality in the reservoir may be markedly different. The vertical compositional gradient in oil column has been documented in many large oil column reservoirs. The geographical variation has been much less documented. In this paper we will demonstrate how variation at the scale of individual sand bodies in the reservoir, sometimes only tens of feet apart, can be very large (as observed in two sand bodies in the same well) and have a dramatic impact on oil property understanding and modeling. In turn understanding of these property variations and their impact on mobility, is a key factor for understanding fluid flow and for the choice of the correct secondary recovery mechanism for an improved recovery. The example of the Wara channelized sand, within the Greater Burgan complex, will illustrate the paper, where downhole fluid analysis is presented as a necessary complementary tool to improve the selection and construction of an accurate set of samples to ensure the data collection is complete and exhaustive before the well is completed.
Overcoming Design Challenges of Chemical EOR in High-Temperature, High Salinity Carbonates
Authors: Levitt David , Klimenko Alexandra , Jouenne Stephane , Chamerois Manuel , Bourrel Maurice 
Published: December 2013

Abstract
The optimization of chemical floods for a low-permeability, high-salinity, high-temperature carbonate formation presents several unique design challenges, which may be overlooked in short coreflood experiments. Low permeability formations require the optimization of polymer molecular weight distribution such that both mobility reduction and injectivity are maximized. The effects of high core-scale heterogeneity must be understood and mitigated, for example, by increasing core length. These subjects are explored in the context of an ongoing flood design project. Understanding and mitigation of pressure build-up issues – possibly related to high surfactant adsorption – is an ongoing challenge. Additionally, an attempt will be made to shed light on the discrepancy between available carbonate capillary desaturation curves for carbonates and the near-complete recovery reported in surfactant-polymer corefloods.
Does your ESP Completion Architecture Meet All Your Production Requirements?
Authors: Camilleri L. , Gambier P. 
Published: December 2013

Abstract
The first electrical submersible pumps (ESPs) were installed nearly 100 years ago by simply running an ESP on tubing in a cased hole. Since then, ESP completion architectures have evolved to cater for a wide range of needs such as dual barriers for offshore operations, reservoir monitoring, flow assurance, backup gas lift, back-allocation for multilayered reservoirs, and dual ESPs for enhanced run life to name a few. These solutions have been made possible by new completion tools which continue to be developed. However, the biggest driver behind the proliferation of completion architecture arrangements has been the creativity of field engineers to meet production and operational needs. Key to justifying additional complexity in a completion is to demonstrate the value, and, to this end, an exhaustive list of functional production and operational requirements was developed and reviewed to serve as a check list for evaluation of artificial lift completion architectures. Establishing the requirements are often overlooked as architectures are often adopted based on what is known or legacy practices (i.e., "This is how we have always run our ESPs.") To illustrate how the functional requirements can be achieved, a wide range of completion architectures were compared and evaluated against the "functional check list" and the review contains references of where these completions have been successfully installed. One of the findings was that, all too often, the completion architecture does not provide a method for circulating the well without losses to the reservoir, which is an important consideration for maintaining flow assurance. Of course, the perfect ESP completion architecture does not exist. However, this review of requirements and completion architectures provides the practicing completion engineer with a methodology for developing the inevitable engineering compromise between cost, complexity, and value based on documented functionality.
Successful Geosteering And ICD Completion In Flank Areas Of Mauddud Carbonate, North Kuwait: Lessons Learned And Experiences Gained
Authors: Nair S. R. , Chetri H. B. , Al-Ajmi H. Z. 
Published: December 2013

Abstract
The Mauddud carbonate, a ‘Major' reservoir in Sabiriyah field, North Kuwait, is about 400 feet thick dominated by carbonates deposited in a ramp environment. The reservoir has ten sub-zones named alphabetically from top MaA to MaJ. Current drilling campaign is being executed on fast track exclusively using Non-Conventional Wells (NCW) in order to achieve production targets.
The planned NCWs are located in flank areas to have optimum exploitation of flank potential. ‘MaB' is target zone as water flood development of the reservoir, as a whole, calls for enhancing the production from MaB and provide the pressure support via water injection at the MAE (Bottom-up approach). The laterals planned are in the range of three to five thousand feet.
Several subsurface challenges were dealt with during design and execution phases. The trajectories are planned with strike parallel azimuths to have minimum inclination changes in lateral sections. The objective is to enable trouble-free operation during ICD deployment. This task was extremely difficult due to local dip changes and variations of actual strike directions. Structure models were constantly updated with real time data and gradual azimuthal shifts were made to achieve this objective. The wellbore must remain in "sweet spot?? throughout. Geological models were used to design trajectories accordingly. This mission was arduous due to sparse well density thereby reducing reliance on models. Presence of sub-seismic faults could place wellbore in undesired stratigraphic positions. Such occurrences were perceived and predicted as best as possible based on regional structural picture and calculated steps were taken. In the eventuality of wellbore hitting unexpected faults, gradual azimuthal-inclination changes were made to correct well paths.
With all these efforts and strategies, the operations team was able to successfully execute drilling and completion of Sabiriyah Mauddud Horizontal wells. The paper is aimed at sharing the success story achieved in North Kuwait.
Selection of Commercial Kinetic Hydrate Inhibitors Using a New Crystal Growth Inhibition Approach Highlighting Major Differences Between Them
Authors: Glénat P. , Bourg P. , Bousqué M.-L. 
Published: December 2013

Abstract
Kinetic Hydrate Inhibitors (KHIs) are one of the two types of Low Dose Hydrate Inhibitors (LDHIs) which are more and more used for gas hydrate control in the oil and gas industry, offering significant CAPEX advantages over traditional thermodynamic inhibitors (e.g. methanol, glycols). As KHIs are traditionally considered "nucleation inhibitors", their lab evaluation is generally undertaken by measurement of an "induction" or "hold" time before hydrates start effectively to form. However, as nucleation is stochastic by nature, obtaining repeatable/transferrable data is often highly problematic and time-consuming, making robust evaluation difficult. A new crystal growth inhibition (CGI) approach has been recently published which showed that KHIs induce a number of highly repeatable, well-defined hydrate crystal growth inhibition regions as a function of subcooling, ranging from "complete" inhibition, through severely to moderately reduced growth rates, ultimately to final rapid/catastrophic growth as subcooling increases. Delineation of these regions provides much more reliable and rapid means to evaluate the relative performance of KHIs under simulated worst case scenario conditions. Nine commercial KHIs have been provided by vendors for one gas/condensate field development in the Middle-East. The screening of these nine KHIs with the CGI method highlighted great variations in their ability to inhibit crystal growth. Furthermore, the ability of some KHIs to completely or severely inhibit hydrate growth even when modest fractions of hydrate (&gt;1% of converted water) are present strongly demonstrates that commercial KHIs can act very differently and that this test method allows to identify "robust" additives compatible with real operating conditions.
New Technologies in Fracturing for Shale Gas Wells are Addressing Environmental Issues
Authors: Nakhwa Amit D. , Huggins Ken , Sweatman Ronald 
Published: December 2013

Abstract
This paper discusses how applied science, historically safe operations, advancements in technology and standard processes are helping to address and reduce environmental issues (EI) for hydraulic fracturing in shale gas wells. The technologies presented include equipment footprints allowing for a reduced risk for environmental effects, 3D fracture mapping, microseismic fracture mapping, "green" fracturing fluids, bacteria control through UV light technology and an improved method of water recycling. This combination of scientifically-derived technologies and best practices (a.k.a standards) is assisting in lowering the risk for EI and addressing misconceptions about hydraulic fracturing.
To further address these environmental issues, members of Oil & Gas (O&G) industry associations, including the American Petroleum Institute (API), Society of Petroleum Engineers (SPE), International Association of Drilling Contractors (IADC) and the International Association of Oil & Gas Producers (OGP) based in London and Brussels, continue to develop sound science and field-proven best practices in the form of industry standards, such as those referenced in this paper.
Technical publications by O&G service companies have provided numerous case histories highlighting these applicable technologies. These presented technologies and practices have helped to demonstrate the positive impacts for shale gas development projects.
New Insights into Surfactant System Designs to Increase Hydrocarbon Production
Authors: Sherbeny Wael El , Bakr Dalia , Quintero Lirio , Jones Tom , Anwar Mohamed , Moussa Doaa 
Published: December 2013

Abstract
Drilling and completing reservoirs without inducing measureable skin damage is rare. Frequently, drilling fluids impact a reservoir’s flow potential while drilling as the rock matrix is invaded by solids and chemicals designed to enhance drilling performance. Drilling fluid can also cause formation damage if they are not properly removed during the displacement phase. These solids can migrate to the perforating zone and cause damage. Completion fluid designs governed by density for well control also often contribute to skin damage. Hydrocarbon flow may be impeded by damage caused by residual drilling debris or incompatible completion and workover fluids, in-situ emulsions, water block, organic deposition, or oily residue.
Specialized surfactant systems have been developed to remediate near-wellbore damage caused by drilling and completion fluids, and damage induced by failed remediation attempts. The properties of these treatment systems include their ability to solubilize oil and, due to a significant reduction in interfacial tension between the organic and aqueous phases, effectively diffuse through the damaged zone to free up flow-resistant obstructions. The inherent properties of these systems make them ideal for removing induced formation damage as well as an excellent option for displacing synthetic or oil-based mud (S/OBM) from casing prior to the completion phase. In open-hole (OH) completions, specialized surfactant designs have proven very effective in removing S/OBM filter cake damage. In cased-hole (CH) completions, they have demonstrated a high degree of efficiency to clean damaged perforations.
This paper presents a technical overview of surfactant systems for OH and CH remediation operations. The testing to qualify these fluids for the removal of damage and field results are presented that show the efficacy of these specialized surfactant systems to remove damage caused by OBM filter cakes and other oily debris to improve hydrocarbon recovery while addressing the operational challenges associated with these jobs.
Challenge and Successful Application for Scale Removal Gemsa Oil Field, Egypt: Field Study
Authors: Elmorsey S. A. 
Published: December 2013

Abstract
Water flooding is the hinge pin for Gemsa Oil Field. Water injection is supplied from shallow water supply wells. Compatibility tests had indicated probable deposition of calcium sulphate scale on surface and subsurface production equipment. Calcium sulphate scale has been recognized to be a major operational problem. The bad consequences of scale formation comprised the contribution to flow restriction thus resulting in oil and gas production decrease. The nature of calcium sulphate scale is very hard and can't be dissolved with known dissolver. Sister companies that has similar problem were always going to the mechanical remover options.
Extensive lab and field work was conducted to determine the suitable chemicals to dissolve calcium sulphate scale. This paper describes the development and field application of chemical treatment to remove scale in an offshore 8" production line in Gemsa oil field. Continuous precipitation of calcium sulphate scale caused partial plugging of the pipeline. This partial plugging created a back pressure on production wells which decreased the productivity. The field production has been decreased to almost one tenth of the normal field production level(1).
A thorough investigation was conducted to identify the composition and location of the scale, in order to recommend a suitable chemical to remove the scale, and to assess the effectiveness of the treatment method in the field.
Based on extensive lab studies, SAG-01 was tested and applied in production line to remove the scale efficiently, the program was designed taking into consideration the nature of the scale.
The treatment program included three - staged process: The use of an organic solventThe main treatment (SAG-01).The post flush stage (injection water),
The job results were outstanding, where as 1-Production increased by about 2,000 BOPD2-Launcher pressure dropped by about 350 psi.3-Decrease the back pressure on our producing wells.4-Additional producing wells into production. Efficient cost /Bbl.
Hydrocarbon Mobility Steering for Optimum Placement of a Power Water Injector above Tar Mats - A Case Study from a Light Oil Carbonate Reservoir in the Middle East
Authors: Saint Craig , Glowig Thomas , Swain Ashis S , Al Khaldi Nasser A. , Al Otaibi Mohd. H. , Al Ghareeb Abdul aziz , Al Bader Ahmad Bader 
Published: December 2013

Abstract
Tar mats are encountered in many Middle East carbonate reservoirs including the Kingdom of Saudi Arabia.
Tar is considered to be very heavy crude that does not flow or has very limited flow capacity at standard reservoir conditions. In some cases it is found above the aquifer and below a light oil layer. As tar is practically immobile at reservoir conditions it acts as a flow barrier between water and light oil, causing significant challenges for reservoir development. In such cases water injectors work most efficiently when placed horizontally just above the tar mat to maintain pressure support during production.
One challenge when drilling for these water injectors is to optimize their position above the tar layer yet as close as possible to the tar to maximize sweep efficiency. A further complication for their placement is the uncertain lateral distribution of the tar in terms of true vertical depth (TVD). The top of the tar layer is often an undulating lateral surface with varying depths.
Positioning the well a "safe" distance from the tar is not a good solution as it might leave behind a significant volume of producible oil, ultimately lowering oil recovery.
A real-time tar detection method is needed while drilling to quickly respond and modify the wells trajectory if tar is encountered.
The low mobility caused by tar can be detected with a formation pressure while drilling (FPWD) tester. A nuclear magnetic resonance (NMR) tool provides oil viscosity estimation and additional tar-related properties. In combination with a conventional logging string, tar can be positively detected while drilling.
This case study from a carbonate field in KSA shows the successful placement of a 6.25-in. horizontal well using a logging-while-drilling (LWD) NMR-device and an LWD formation pressure tester to detect tar in combination with conventional resistivity, density and neutron (triple-combo) LWD logs.
Restoring Integrity of the Platform by Abandoning Gas Producer Well Suffering From Integrity Problems
Authors: Mohamed Shanof , Al-Hosani Ibrahim , Al Neaimi Ahmed K. , El Sayed Mohamed , Abdelsalam Mohamed 
Published: December 2013

Abstract
This paper presents the innovative planning methods and highlights of the operations completed for the abandonment of a gas producer well suffering from integrity problems thereby restoring the integrity of the platform and putting the other wells on production. The integrity problems were oil/gas bubbles seen on the sea bed around the conductor pipe and high sustained pressures in the outer cemented annuli of 18 5/8" × 13 3/8" and 13 3/8" × 9 5/8". The entire tower/ platform was considered highly dangerous and unsafe under these conditions and the tower was risk ranked No. 1. Consequently, the wells on this platform were secured in January 2001.
A task force was formed to investigate the problem and propose solution. The team proposed to permanently abandon the gas well to restore the integrity of the tower. The possible source of leak was identified by monitoring the annuli pressures, measuring fluid samples, running noise and temperature logs and leak rate tests. After analyzing all the problems, the team agreed to isolate the source of leaks by remedial squeeze jobs through selected perforated intervals with additional barriers like bridge plug. International standards were adopted in planning for the abandonment of this well.
There were several challenges involved in the abandonment of the well like identifying the possible leak sources, perforation against 4 casings, adopting international standards for abandonment, choosing the type of barriers, cement type, ensuring the integrity of the barriers etc. Finally, the team through continuous effort and hardwork overcame these challenges, produced a robust plan and executed the operation safely in cost effective manner.
The paper serves as a good reference for the abandonment of gas wells following international standards and other areas include perforation against four casings.
Improved Dehydration and Desalting of Mature Crude Oil Fields
Authors: Sellman Erik , Sams Gary , Mandewalkar S. Pavan 
Published: December 2013

Abstract
Mature crude oil fields most often contain higher water cuts and higher content of fines. The combination of a large population of water droplets and fines form very stable crude oil emulsions that are difficult to break.
The higher water cuts provide higher crude oil emulsion viscosity because of the larger population of small water droplets, often leading to a need for higher operating temperatures, frequent production upsets and high demulsifier dosage.
Another challenge is arcing between electrodes as a result of the higher water cuts. Typically older crude oil dehydration and desalting treaters use AC type electrostatic technology, which are less effective in treating crude oils with higher water cuts.
The use of combined AC / DC electrostatic technology provides a two prong approach where bulk water is removed in a weaker AC field and remaining smaller water droplets are removed in a stronger DC field. Further improvements to the AC/DC treaters include use of composite electrode plates, modulated electrostatic fields as well as improved fluid distribution inside the treaters.
AC / DC treaters provide an attractive opportunity for retrofitting existing AC treaters in mature fields and make the treaters more suitable for dehydrating the crude oil emulsions from these fields.
This paper describes new enhanced electrostatic dehydration technologies suitable for treating higher water cut crudes from mature fields, efficient test methods for optimized usage of production chemicals and selection of electrostatic technologies, including case studies.
Asset Integrity Management System Implementation
Authors: Rezaei Cyrus , Abbas Ahmed A. 
Published: December 2013

Abstract
KOC commenced preparation of Integrity Management (IM) System Standard & Guidelines in 2003. The IM system implementation sits under HSE umbrella at present and compliments the existing HSE management system policy and procedures. KOC operations assets include North Kuwait (NK), WK, S&EK, Gas Operations/Management and E&PD (Exploration & Petroleum Development). Major Projects are also managed by TSD (Technical Service Directorate) & Controlling Teams including Inspection & Corrosion. Initially, a set of six critical areas for IM implementation was agreed with the operating assets and KPIs (key performance indicators) were defined accordingly. These comprised of chemical management system, safety critical equipment, emergency shutdown system testing, fire & gas detection system, replacement of pipelines temporary clamps with permanent ones and procedure for control & monitoring of safety overrides equipment. Previous integrity related incidents were analysed to identify the immediate and root causes and a basket of IM KPIs was prepared accordingly. The analysis also included the minor incidents, near misses, unsafe acts & conditions and lessons learned from inside and other Oil & Gas companies. Each asset selected a number of KPIs as applicable to the nature of their operations and prepared a 3 years rolling plan accordingly. Each asset monitors implementation of their selected KPIs and quarterly performance reports are compiled in an auditable manner. Achieved KPI targets are sustained for continuous improvement cycle & new KPIs are introduced into the IM basket as/when identified. IM system has now focused on PSM (process safety management) related aspects and incident prevention. Although the HSE management system has been focused on personal safety, IM/PSM system is aiming to enhance the process safety and prevent PSM related incidents. This provides a more holistic approach to enhance personnel responsibilities, competency development, safety critical equipment identification & respective PM (preventive maintenance) plans and incorporation of Inherently Safer Design (ISD) principles in project concepts to prevent loss of containment.