bluuebunny/crossref_metadata_2025_split huggingface dataset:
Application of Friction Reducing Rigid-Resin Centralizers Based on Silicon Carbide
Authors: Javier Urdaneta , Mauricio Tarache , Carlos Gonzalez , Luis Quiroga , Ramirez Zoraya , Silva Paula , Ingrith Villamizar , Oscar Zuleta 
Published: March 2015

Abstract
Market dynamics are forcing petroleum operators to undergo complex drilling operations in remote locations in search of new sources of oil. This change in approach has meant that new technologies play an important role in the planning and development of such projects.
Because of deeper well drilling construction, running casing has become a challenging operation. The use of rigs with high torque and drag capacity, pipes with premium connections, and chemical lubricants in the mud make drilling projects significantly more expensive. The complexity of well construction has led to running casing and effective zonal isolation being major challenges, wherein operational practices limit the ability of powerful rig equipment, and thus the length of each section. For this reason, reducing the friction factor has become a key to building high inclinations and extended reach wells.
Rigid-resin centralizers based on carbon fiber ceramic composites have been applied successfully for highly tortuous wells. The use of friction reducers can improve the efficiency of running casing and help secure its settlement to the desired depth, helping reduce time, lowering costs, and minimizing problems. Running centralization in different casings and liners can have the effect of raising the string off the low side of the well, reducing contact area (drag) and improving cleaning efficiency during circulation. This results in less time washing and reaming during runs through interbedded formations.
This paper presents the advantages of using friction reducers chemically bonded to the casing to help reduce torque and drag and maximize casing standoff for primary cementing operations. The knowledge, lessons learned, and field procedures described can be applied to help address zonal isolation problems in vertical, deviated, and horizontal wells with high dogleg severity, helping reduce both operational time and associated costs.
Excellence in Environmental Technology and Stewardship — Manifa Mega-Project
Authors: Arukhe James , Abdulelah Balto , Yateem Karam , Namlah Sultan 
Published: March 2015

Abstract
Completion of the Manifa field development mega-project marked the world's largest hydrocarbon production increment in a single phase. Just as significant as its considerably large production scale, the project involved several green initiatives, including broad-spectrum environment conservation and protection, air pollution controls, and coastal/marine protection. Manifa's coastal and ecologically sensitive location is a source of livelihood for local farmers and contains habitat for fish, shrimp, coral reefs, and endangered species. Consequent upon the richness of species in the zone, the field warranted a development solution that was a balance between environmental stewardship and operational excellence. During Manifa's field development, a critically important environmental strategy was also developed for the construction of the causeway, central processing facility, gas and oil separation, water injection, and cogeneration plants, and 15 offshore platforms for oil production and water injection, with associated subsea pipelines and power communication cables.
An environmental impact assessment (EIA) was completed and a continuous environmental monitoring program (EMP) was implemented during dredging and disposal of dredged materials, prior to and during the construction location of 27 man-made islands to achieve the EIA's mitigation criteria and guidelines. Four (4) studies were also commissioned by the King Fahad University of Petroleum and Minerals (KFUPM) in collaboration with the Spanish research institute AZTI-Technalia.
The successful grassroots development of Manifa, without sacrificing a responsibility to protect the environment, is a testimony to the careful integration of interdisciplinary approaches from project onception to completion; and from exploration to delivery of hydrocarbons to end users. Innovative solutions led to contractor partnering, a strong health, safety and environment (HSE) culture and an exemplary environmental awareness and conservation approach, which resulted in a successful project with a positive influence on Saudi Arabia, the region and other parts of the world.
Proper Planning Supported by Latest Technology Leads to Drilling the Longest 8.5-in. Section in an Extended-Reach Well: Case Study
Authors: Chima Jude , Umarin Isa , Kunhiveetil Dhanraj , Otaif Hassan , Al Dabyah Ali , Zubairi Bilal , Mayer Heinrich 
Published: March 2015

Abstract
Over the past years, extended-reach drilling (ERD) field development has significantly increased globally, and its benefits are well recognized. ERD techniques are increasingly used to intersect hydrocarbon targets that are difficult to access due to logistic issues. While these wells are challenging to drill, complete, and service, the benefits can be wide ranging. These benefits drive the development of technology and techniques to continuously expand the ERD envelope and increase the complexity of profiles to reach more challenging targets. The directional drilling and evaluation service supplier plays an important role.
Each ERD well has a unique set of challenges. Common to all ERD projects is that many aspects of drilling engineering principles are not only pushed to the limit, but become highly interrelated and sensitive to smaller changes than conventional wells. For this reason, a team approach to planning and executing ERD activities should be considered critical. Each team member should bring to the project relevant experience, knowledge, a range of field-proven technology, and a solid global support structure.
Drilling successful ERD wells in challenging conditions depends on various factors, which include careful planning and use of the latest technology. Planning involves understanding the geological structure, not only within the reservoir section, but also in the overburden where typically most of the time efficiency gains can be achieved. The last step in planning is designing an efficient bottomhole assembly (BHA) based on previous experiences, lessons learned and inputs from various teams. Good planning is supported by use of new technologies, especially tools that give real-time information, enabling quick and informed decisions to ensure safe and efficient drilling in a challenging environment. The paper discusses the planning and decision-making process to drill ERD wells by using latest real-time technologies in drilling challenging wells. This paper will describe the experiences and huge success of drilling the longest 8.5-in. hole section in an ERD well, drilled and cased smoothly through challenging formations.
Non- Coiled Tubing Stimulation of Water Injectors
Authors: Mahmoud M.A. , Abdelgawad K.Z. , Akram A. , Stanitzek T. 
Published: March 2015

Abstract
Sea water is injected to maintain the reservoir pressure that supports the oil production from carbonate and sandstone reservoirs. The Gulf sea water contains more than 4000 ppm sulfate and the formation contains more than 19000 ppm calcium, this will cause calcium sulfate precipitation at the reservoir conditions. The precipitate at the reservoir conditions will be anhydrite and it will cause formation damage that will reduce the well injectivity. Stimulation treatments are required to recover the well injectivity and this requires stopping water injection to perform the stimulation treatments.
In this study we are proposing a new method that we can use to stimulate water injectors without stopping the water injection. The new method includes adding a chelating agent to the injected sea water at the well head at 15 wt% concentration. Several solubility and coreflooding tests were performed using actual carbonate cores and the new chemical at different temperature ranges. The chemical injection does not need coiled tubing and can be injected at the surface with the sea water. The chelating agents will sequester all calcium in solution and will prevent the calcium sulfate precipitation. The chelating agent used in this study is GLDA.
Solubility tests up to 250°F at high pressure showed that the GLDA is stable with the sea water. Coreflood experiments and CT scans showed the ability of GLDA in the creation of nice wormholes through a 6 in. and 1.5 in. carbonate cores at 100 and 70°C respectively. The GLDA chelating agent can be used to stimulate sea water injectors without any additives as this chemical is stable and is gentle with the well tubulars. Previous corrosion studies on GLDA showed that its corrosion rate is in the allowable range without adding corrosion inhibitors.
Successful Downhole Sampling in HPHT Extreme Sour Exploratory Wells Using DST Sampler.-Case Studies
Authors: Al-Salali Yousef , Al-Bader Haifa , Al-Ibrahim Abdullah , Sagar Vidya , Manimaran A. , Packirisamy S. , Rajkhowa Anupam 
Published: March 2015

Abstract
Jurassic reservoirs in Kuwait fields are deep (upto 17,500 ft), high-pressure (&gt;10,000 psi), high temperature (300°F) and having high H2S concentration upto 35%. Additionally, some reservoirs are having super saturated saline water. Exploratory wells drilled in these reservoirs are tested with Drill Stem Test (DST) tools. High quality reservoir fluid sample is necessary for meaningful PVT studies, which is very important for assessment of reserves and for future development. Many wells were tested in deep reservoirs but BottomHole Samples (BHS) could not be collected in most of the wells due to extreme well conditions namely well deviation, HPHT, H2S upto 35% and salt deposition inside tubing. Generally, Well Head Sample (WHS) and/or separator samples are collected for PVT studies. Downhole samples are preferred for carrying out PVT studies. However, using slick line/wire line for collecting downhole samples was considered unsafe and having potential risk due to extreme well conditions. Keeping in view of well profile and hostile environments, provision was made to collect representative reservoir fluid sample using downhole sampler in DST assembly. The DST sampler is rated to 20,000psi and 400°F, can collect upto nine 400cc samples, and are activated in sets of three by annulus pressure. It was very challenging to operate the downhole DST sampler, as the mud used in the annulus was as high as 20.8ppg OBM.
A pilot study on this DST sampler was implemented in two different exploratory wells. Reservoir fluid samples of sufficient quantity were collected at downhole condition in hostile environment. Quality of samples collected during DST is good and these samples were used to characterize the reservoir fluid. Based on the successful results, it has been planned to use DST sampler in these hostile environment in future.
This paper describes successful downhole sampling DST design/tools, together with the techniques implemented to obtain representative reservoir fluid samples at downhole.
Facies Architecture, Channel System and Paleoflow Pattern of a Young Sandstone Reservoir using Borehole Resistivity Images
Authors: Ahmed Khalid , Ferdous Hasan , Choudhary Pradeep K , Abbas Faisal , Al-Khamees Waleed , Helba Adly , Osman Adham , Ali Wael , Fatah Mohsen Abdel , Vasquez Rafael 
Published: March 2015

Abstract
The Miocene age shallow unconsolidated sandstone formation in Kuwait contains viscous oil whose distribution is primarily controlled by depositional facies and their diagenetic modifications. This study integrates core-calibrated resistivity images with openhole logs to obtain high-resolution facies logs with continuous array of oriented depositional structures, facies types, and environment-related facies associations with paleocurrents measurements. These are combined in defining reservoir zonation, geometry, spatial distribution and paleo-geographic evolution during its accretion across the field.
The formation is characterized by variable grain sizes, sedimentary structures and diagenetic cementations. The sandstone succession is punctuated by scouring surfaces and separated by discrete mudstone intervals mixed with scattered bioclasts. The upper section of the formation encompasses two main oil-producing sandstone intervals (S1 & S2 reservoirs), separated by a mudstone unit (Mid Shale) and sealed on top by marine Cap Shale unit. Each sandstone interval consists of lower sheet-forming stacked horizontal-and cross-stratified sandstone units (S1B & S2B) and upper lenticular sand-prone bodies (S1A & S2A) that laterally truncate or intermingle with units of sandy mudstone and argillaceous sandstone (S1 Shale & S2 Shale).
The observed physical and biological features, paleocurrents data and vertical hierarchy of recognized sandstone and mudstone facies suggest the oil-bearing sequence formed as fluvial to upper delta-plain deposits that were accreted by repeated lateral shifting, and an overlapping of fluvial channels, distributary/abandoned channels, crevasse splays and inter-distributaries lakes or bays of estuarine origin. The active fluvial-and distributary channels were generally flowing from SW to NE, and locally due E and SE, and largely discharged from S. The morphological parameters reveal that the fluvial channels migrated laterally and bifurcated downstream, and fluctuated across a low sinuous channel belt. With continuous base level rise, the area was drained entirely by transgressive brackish-water lacustrine or bay events depositing the widely distributed Mid-Shale and Cap-Shale units.
Integrating Flexibility in New Development to Formulate Optimal Depletion Strategy with Reduced Risks in a Complex Carbonate Reservoir in Middle East
Authors: Vinayagam Vinoshen 
Published: March 2015

Abstract
The field of interest is an anticlinal structure aligned Northwest-Southeast, about 31 km long and 10 km wide. The field was discovered in 1984. The major reservoir, M is further subdivided into M1, L1 and L2. It is a carbonate reservoir containing approximately 75% of the total field Stock Tank Oil Initially In-Place (STOIIP). Other reservoirs are Y, Z and R.
The biggest uncertainty in preparing a Field Development Plan (FDP) for the field is the subsurface uncertainty due to limited data availability. Areal and vertical heterogeneity are evident even from the early production data. These came at no surprise as available core data, well testing data and other pressure data suggest the same.
“Oil Spillage Environment Impact Reduction Based On Automated Leak Detection on Rod Pumping Wells in South of Oman”
Authors: Mahrooqi Salim Al , Gonzalez Maximiliano , Marcano Miguel , Vargas Luis , Harthy Abdullah Al 
Published: March 2015

Abstract
The environmental impact of oil spillage and additional costs associated in oil fields is an important matter, especially in large oil fields, where well sites monitoring and spills prevention are not easy tasks; therefore a new spillage management detection is an utmost required.
Petroleum Development Oman (PDO) has more than 1700 Beam lift wells operating in the South Oil Directorate. In the latest years the Stuffing Box (SB) leaks have become a serious issue in field operations, causing a severe environmental impact as well as a significant additional operational costs and unscheduled production deferment.
In most of the cases the SB leaks are related to wellhead or Beam Pumping surface unit misalignment, which somehow affect the mechanical condition of Polished Rod (PR) limiting its run life. When the PR is not aligned with the axial bore of the SB a lateral force exerts upon the SB by the PR is producing severe wear and premature failure of its rubbers elements resulting in SB leaks. In many cases when the SB leak begins, the spillage get overflow on the location resulting in an environment damage and unnecessary deferment due to BP outage.
Solution to the above problem lies in automation, which is also key success factor in every phase of oil production process. It allows production processes monitoring, as well as its optimization and controlling, aiming to reduce costs and maximizing the overall system efficiency. The tangible and intangible savings generated by these automation systems have exceeded customer/operator's expectations in all cases, where spills have been significantly reduced and early SB leaks have been successfully detected and corrective action there upon taken.
This paper gathers the results of field investigations conducted to understand causes behind of SB's integrity loss, which might lead to severe fluid spillage on well locations. Furthermore, presents the new operational philosophy, which could reduce company exposure in terms of HSE risks and additional operational costs associated with management of oil spillage.
Developing Risk Profiles for Produced Water Re-Injection Utilising Advanced Imaging Technologies
Authors: Bhola N. , Ariaratanam G. , Roth N. 
Published: March 2015

Abstract
Online particle measurement is one of the key technologies in characterising fluid quality and developing strategies to ensure the efficient operation of and optimise any separation process. Online imaging systems have the benefit of being able use their multi-dimensional data to provide more information than just particle size, as particle shape, aspect ratio and many other parameters measured can be used to identify and classify different types of particulates, such as oil droplets and solid particles in a produced water system.
This understanding of particle type, size and shape provides a significant step forward over simple particle size as it enables separation process design and operation to specifically treat and remove target particulates. In this paper we will examine case studies that demonstrate how specific particle information can be used to understand and optimise different treatment stages within a produced water treatment system.
Agglomerates appear frequently in some fluid systems and can confuse imaging systems where simple parameters are being used to differentiate between particle species as the agglomerated material will present with different shape characteristics to those of its individual constituent particles. We will review produced water systems where the chemicals used to aid separation, and some of the separation technologies themselves, operate by creating aggregation and agglomeration using case studies demonstrating these effects. We will discuss where agglomerates commonly occur and what significance these particles have within the oily water separation process. We will review the latest imaging software package that is capable of identifying these types of agglomerated particles and assessing constituent components.
Finally we will assess how this information contributes to our understanding of the risk profile that these types of agglomerated materials present in produced water re-injection and how that risk profile may be developed and analysed in the future.
A Decade of Experience with MPFM in Northern Fields of Saudi Aramco
Authors: Al-Kadem Mohammad S. , Al Khelaiwi Faisal T. , Al Mashhad Ali S. , Al Dabbous Mohammad S. 
Published: March 2015

Abstract
Multiphase flow metering is considered one of the most essential technologies in well testing. Since the mid 1990's, Multiphase Flow Meters (MPFM) have evolved from a revolutionary new technology into a consolidated solution widely adopted by the major operators worldwide. This evolution has taken place thanks to the high quality of measurements, low operational cost and the capability of enabling remote monitoring of wells' performance and testing with ease.
The installed MPFMs in Northern fields of Saudi Aramco have contributed effectively to enhancing the semi-real time measurements' quality as well as improving reservoir characterization. Though, MPFMs are prone to mechanical and firmware failures. The MPFM technology largely seems to be performing as expected and delivering high quality data. So far, 58% of the systems have been in service for more than 8 years and continuing to operate efficiently.
Thorough analysis of the routine maintenance and checkups conducted during the past 10 years revealed the following:
The MPFMs Mean Time between Failure (MTBF) and Mean Time to Repair (MTTR) indicated that the MPFMs have been available 97% of the time. The use of a probabilistic approach (Monte-Carlo™ Simulation) to study the P10, P50 and P90 values of the maintained MPFMs indicated that the variance between these values is small, demonstrating the reliability of these equipment. The classification of the diverse types of problems faced while operating the MPFMs highlighted the dominant cause of failures and enabled the initiation of a surveillance and subsequent failure mitigation program.
This paper discusses the lessons learnt and experience gained from operating 168 MPFMs provided by different vendors in different environments during a 10-year period, along with the appropriate solutions that were implemented to mitigate the challenges faced and subsequently improve the efficiency and data quality of the MPFM.
Extensive Fracture Diagnostic Tests and Customized Workflow Lead to Successful Characterization of Deepest Unconventional, Tight and Sour Dolomite Formation in North Kuwait
Authors: Al-Zaidani Ibrahim Mahamed , Barasia Ankur , Al-Failakawi Abdul Aziz , Fidan Erkan , Sharma Siddhartha Shankar , Samad Zamzam Mohammed , Khayan Andre 
Published: March 2015

Abstract
Appraisal program of the deep gas/light oil from unconventional reservoirs in North Kuwait is strategically important to secure the challenging hydrocarbon production targets of Kuwait Oil Company (KOC). A very deep high-temperature/high pressure (HT/HP) dolomitic formation is at approximately 15, 000 ft (vertical), poses complex completion and producibility challenges. Exhaustive log suite and core analyses confirm some porosity development and gas shows. Unlike the proven carbonates up-hole in the same asset, the deepest dolomite units have extremely low permeability, and may not flow unless enhanced by a natural fissure network and/or hydraulic fracturing.
Only a few wells have been attempted for completion in these deepest dolomite layers, which failed to flow even after matrix acidizing treatments. The effective completion design will require good understanding of formation mechanical properties and fluid leakoff behavior, leading to optimal horizontal wells to maximize reservoir exposure completed with multiple hydraulic fracturing treatments to establish hydrocarbon production at commercially acceptable rates. Therefore, properly designed and effectively executed extensive fracture diagnostic tests are critical in the current pre-appraisal stage. In addition, multiple acid-fracturing treatments have already contributed to the understanding of fracture geometry development and fracture flowback characteristics.
A fracture diagnostics workflow was developed and deployed to appraise the deepest dolomite layers. Critical fracture mechanics data were collected and analyzed. The main fracturing treatments have also yielded crucial results, which will help the design team in optimizing the horizontal well completions. This comprehensive workflow can be successfully applied in characterizing challenging formations elsewhere where the well and regional data are limited in the appraisal of similar light oil/tight gas-bearing unconventional carbonates.