bluuebunny/crossref_metadata_2025_split huggingface dataset:
Effect of Sand Deposition in a Riser: Case Study of the Jubilee Field Riser
Authors: Anthony William , Owusu Mark 
Published: March 2015

Abstract
Sand production is a common phenomenon in hydrocarbon extraction. It is the migration of formation sand as reservoir fluid flows, and can accumulate downhole around the production interval thereby blocking the production interval, and hence reducing production rate.
The Jubilee Field experienced sand production during its early production stages. Although the challenge has been addressed through acidising, however, sand production is inevitable as the field matures. It is always desirable to have these sands flow through the riser to the surface. The flow conditions, the sand flow dynamics and the riser bathymetry could lead to sand deposition and accumulation in the riser. This study examines the flow dynamics and the effect of sand deposition on the flow integrity in a typical riser using computational fluid dynamics. It uses the Jubilee Field East Loop riser as a case study.
It has been deduced that for the given flow conditions, there is the possibility of sand deposition and/or accumulation in some sections of the riser, and that low points in riser bathymetry are possible sources of onset for sand deposition. Sand dispersion decreases from the point of injection towards the lower region of the flow domain downstream from the injection point. Flow pressure and velocity were significantly affected by sand deposition and/or accumulation within the flow domain especially areas in the proximity of low points. The study established that uncontrolled deposition and/or accumulation of sand within these sections of the flow have the possibility of changing the flow characteristics within the riser.
This study would aid in proposing effective strategies to mitigate the impacts of sand deposition in a riser. It will contribute significantly to the implementation of an effective pressure and sand management strategy.
Revelation of the Triassic Gas Potential with Insight of Iso Frequency Spectral Decomposition in Saudi Arabia's Offshore
Authors: Sodagar Taher M. 
Published: March 2015

Abstract
Two fields in the eastern offshore of Saudi Arabia were evaluated for the feasibility of an Iso Frequency Spectral Decomposition (FSD) approach to recognize the hydrocarbon presence in two key Triassic reservoirs – Minjur and Jilh formations. Another essential objective was the integration of an advanced Iso FSD technique with other traditional seismic attributes, to identify new possible hydrocarbon sweet spots at the same reservoirs, as well as new potential Triassic plays in the study area. Wells in the first field have hydrocarbons in logs and from tests in the Triassic reservoirs, while a well in the second field shows no hydrocarbon of any kind. 3D seismic data was used to create acoustic impedance inversion and FSD data volumes. Gas bearing reservoirs typically diminished more rapidly at the high frequencies than wet reservoirs. Incremental FSD volumes from 5 to 40 Hz were generated to identify gas saturated locations. Reservoir maps were also produced for seismic amplitude, inversion and FSD attributes.
The frequency maps for the Triassic aged formations demonstrated sweet spots at the first field and dimmed at the second field at 10 Hz, while diminishing rapidly at these sweet spots on higher frequency maps. The inversion map for the Minjur Formation displayed low impedance at both fields. The inversion map for the Jilh Dolomite reservoir exhibited low impedance at the first field and high impedance at the second field. The inversion map for the Lower Jilh (a new play) showed relatively high impedance at the first field and fairly low impedance at the second field. The FSD and inversion maps consistently agreed with the offshore Triassic wells for gas detection and porosity. The seismic attribute maps integrated with Iso FSD maps led to identifying potential drill locations with good porosity and gas detection within Triassic formations in Saudi Arabia's offshore field areas.
Case Study: Promoting an Effective HSE Culture in a Young Joint Venture with a Massive Operation to Rejuvenate a Mature Field
Authors: Hussain T. , AlJamea D. 
Published: March 2015

Abstract
Discovered in 1932, the Bahrain field is one of the oldest oil fields in the Middle East. In 2009, a new Joint Venture company comprised of international oil companies was created, Tatweer Petroleum, with the objective to rejuvenate the mature Bahrain field reservoirs.
Tatweer Petroleum immediately embarked on a massive field-wide development plan managed by an army of 800 employees and more than 5,000 contractors. The vigorous operation involved parallel execution of major infrastructure projects to accommodate new production from 650 new wells (drilled in 4 years) that included debottlenecking of existing facilities, a new power distribution system, tank batteries, well manifolds, gas compression, gas dehydration, water treatment plants, and steam generation plants, as well as several environmental, health and safety improvement projects.
The magnitude and pace of the redevelopment activities posed a continuous challenge on the Health, Safety and Environment (HSE) team who had to ensure compliance with local and international HSE standards and meet tight company KPIs and HSE targets.
Leveraging valuable, rich experience and safety cultures of its international partners, Tatweer Petroleum effectively launched several HSE initiatives that significantly improved the HSE performance of the operations.
This paper presents how Tatweer Petroleum managed to achieve high HSE standards through the implementation of a series of aggressive campaigns and programs side-by-side with the massive operation citing three examples of these HSE initiatives.
Large-Scale Physical Simulation Experiment Research for Hydraulic Fracturing in Shale
Authors: Wang Yonghui , Fu Haifeng , Liang Tiancheng , Wang Xin , Liu Yunzhi , Peng Yi , Yang Lifeng , Tian Zhuhong 
Published: March 2015

Abstract
Successful development of shale gas in North America triggered great enthusiasm of developing shale gas in China. Experiments for hydraulic fracturing shale Outcrops sample in 762×762×914mm(height) were performed by using large-scale true tri-axial testing system to study what kind of hydraulic fracture will be for South China marine shale and how the formation condition or the human-controllable parameter influence the fracture complexity. Investigations of fracture geometry and fracture complexity are conducted with different natural fracture distribution, different main stress difference, different fracturing fluid viscosity, different injection rate, using methods such as acoustic emission monitoring and cutting the rock sample into pieces. The testing results show the hydraulic fracturing in shale generates more complex fractures than that of in sandstone, where both tensile and shear cracks are observed. Natural fractures, shale bedding and small principal stress differences are in helping to form complex fractures. When a low viscosity fluid is used, complex fractures are easier achieved than that with high viscosity fluid. This work explores a way of conducting hydraulic fracturing large-scale shale test. The testing results provide important basis for numerical simulation of fracture propagation, pre-frac layer or stage choosing and fracturing design optimization for hydraulic fracturing in shale.
Case Study: Design, Execution and Results of Retrieving Challenged Gravel Packs, the Future in Workovers
Authors: Gonzalez Luis D. , Costeno Hugo , Djohor Mohamed , Curteis Charles , Raziyev Mukhamed , Rivero Maria 
Published: March 2015

Abstract
Workover is the process of performing major maintenance or remedial treatments on an oil or gas well to restore, prolong or enhance its production. The complexity of workover operations is increasing due to the well conditions faced, such as age, environment, mechanical restrictions, completion design, number of completed zones, downhole equipment installed, etc.
Well workover can represent up to 49% cost reduction over its sidetrack option, making it economical; but it may require good sand control understanding, and comprehensive procedures, to retrieve existing gravel pack (GP) assemblies, an operation that possess the risk of getting stuck and/or being unable to retrieve the assembly and eventually abandoning the well. For many years the Oil Industry has rejected workover candidates because of risk aversion overriding cost and value added; the actual workover opportunities include new challenges such as retrieving Alternate Path screens.
This paper discusses the design, risk management approach and the challenges faced during execution, as well as the lessons learnt, of two workover wells in a brown field; both candidates had several challenges such as: Old completion,Lack of reference data,Length of screens (500 ft of screens)Sand productionDifferences to retrieve Wire Wrap and Alternate Path screens
The two successful retrieval of the sandface completion in both wells were the first and second operation of its kind performed by the operator and provide field experience and best practices for future similar operations. Furthermore; the study of the retrieved assembly, after over 20 years of production, helped to understand the sand management system failure mode and the reasons for the sand production issue; knowledge that will impact future well designs in the field.
An Innovative Inflow Control Device Technology with Sliding Sleeve Functionality Maximizes Recovery in Horizontal Wells
Authors: Lee Byung , Julaih Ali Al , Gavioli Paolo , Vicario Roberto , Suherdiana Hedy 
Published: March 2015

Abstract
Horizontal wells drilled in heterogeneous reservoirs present several challenges for reservoir management. Issues like early water breakthrough and inefficient drainage around the well in a reservoir with high contrast in permeability are very common in horizontal wells. An effective approach to address the challenges of horizontal wells and to increase the oil recovery is to complete the wells with inflow control device (ICD) technology.
Most ICD technologies available in the market are passive inflow control devices that do not have the ability to change properties when unwanted fluids break through. The new ICD not only incorporates the benefits of passive ICD technology, it also incorporates sliding sleeves in the module that can be closed whenever the ICD starts producing water. This helps maximize the oil production from the well and reduces the problems related to handling of water at the surface facilities.
This paper will demonstrate the effectiveness of the new hybrid ICD design. It is novel viscosity insensitive and may provide higher restriction to water over oil, and the successful operation of the sliding sleeve feature through a field case of a well drilled in a carbonate field in Middle East. Bottomhole pressure and weight indication observed through specialized fiber optic-installed coiled tubing confirmed the operability of technology by proper opening and closing of sliding sleeve. A fluid flow profile recorded by a production logging tool (PLT) on the same CT proved that the completion effectively equalized flow along the wellbore and will delay eventual water breakthrough while still producing at the desired production rates. PLT proved that the custom-designed completion with its appropriate number of compartments, number of ICD joints and flow resistance rating, achieved an optimized ICD completion.
Flow-Based Effective Properties of Sub-Seismic Karst
Authors: Jones Gareth D 
Published: March 2015

Abstract
Evaluating uncertainty in reservoir performance related to karst is a fundamental challenge for field development planning and optimizing recovery. Deciding which karst features matter-to flow and how to capture their effect for flow simulation is a critical, but uncertain step in developing an appropriate reservoir characterization and modeling strategy.
Our ability to characterize karst is compromised by the type, resolution and relative abundance of different measurement methods. Many sub-seismic karst features fall in a “data gap” because they have dimensions and networks of pores that are not, or only partially, resolved in typical subsurface datasets. Outcrop analogs and cave maps provide a bridge to address this “data gap”. A specific challenge is how to capture the flow significance of karst features that are smaller than a full field scale geological model cell.
This paper presents a workflow using high resolution geologic models termed element modes to address this karst characterization and modeling challenge. Element models were populated with distinct geological configurations of sub-seismic karst and matrix. Flow-based averaging was used to calculate the effective reservoir properties at the scale of a full field geologic model cell. Karst was populated using two different facies modeling methods: 1) Object Based Modeling (OBM) and 2) Multiple Point Statistics (MPS).
Results for two karst examples presented demonstrate that the presence of certain types of karst, even &lt; 5% by volume in a geological model cell, can increase the vertical permeability by an order of magnitude or more relative to a matrix only case. In contrast the effect of karst on horizontal permeability is less significant. Permeability anisotropy (kz:kx) is therefore increased. The karst: matrix property is common to both the element and full field model and can be used as the link to populate effective properties at the field scale.
“Model Assisted Characterization” experiments with efficient fast-to-run high resolution element models, that capture distinct styles of karst, in combination with flow-based averaging optimizes the characterization workflow and provides a richer understanding of irreducible uncertainty that expedites geologic model design.
Developing People through Mentoring to Transfer Knowledge and Technology
Authors: Al-Mutairi Saleh H , Al-Jummah Reem J. , Bou-Mikael Sami , Al-Aruri Ahmad D. , Raju Vegesna Venkata , Izzett Paul 
Published: March 2015

Abstract
Saudi Arabian Chevron (SAC) is continuously investing in human resource development and technology as an integral part of its business operations. Newly hired graduates go through a variety of training and performance management programs to enable them to be globally competitive members of the Chevron workforce. A comprehensive and structured manpower development program called “Horizons” is implemented within Chevron to accelerate the development of new graduate hires.
A key enabler for delivering on SACs graduate development commitments is through its newly inaugurated Technology Center. The Technology Center is acting as the center of excellence for manpower development and technology transfer to SAC. The Horizons program consists of three key elements; a) technical training; b) rotating job assignments; and c) mentoring. Technical training, with a mix of both cross-functional and discipline specific topics, is designed to improve competencies of new graduates. Rotating job assignments allow participants to gain practical experience and petrotechnical skills by becoming involved in a variety of hands-on projects. The mentoring program assigns each young employee with a senior technical professional to enhance competency through knowledge sharing and to guide the career planning and development process. The SAC Technology Center provides technical support to the assets through various projects, including technology deployment, static and dynamic modeling, reservoir management and drilling and completions technology. A key objective in all of the Technology Center projects is to provide opportunities for the young national talent to learn through enganement in ongoing projects.
This paper highlights key components of the accelerated development program and technology transfer process implemented in Saudi Arabian Chevron by the Technology Center. With a structured and focused approach to the development of national talent, SAC feels it will be able to achieve effective and reliable transfer of the Chevron corporate culture and knowledge to meet the future human resource needs of the Company.
Geosteering Horizontal Wells in Ultra-Low Resistivity Reservoir at Flank of a Field in Northern Oman
Authors: Lim T. , Goossens P. , Soden L. , Angelatos M. 
Published: March 2015

Abstract
Geosteering horizontal wells in the flank of a flatly dipping structure is the focus of a PDO waterflood development project since 2006. The reservoir is a carbonate Shuaiba formation in central north Oman. As the crestal areas have been fully developed, the future development focus is in the flank, which is located within the transitional oil column. This column has a low oil saturation that can vary from 35% to 50% in the first top 2m of the reservoir. Consequently, to avoid leaving attic volumes, wells need to be placed as close as possible to top of reservoir while avoiding penetration of the highly unstable overlying shale.
This field has unique geosteering challenges. The reservoir-caprock interface is an erosional surface which is complicated further by resistive and cemented layers, faults and fractures. These features can deflect the drilling bit for a few degrees in inclination, which seriously affects the geosteering capability. Regarding log analysis implications, the ultra-low resistivity (~0.5 ohmm) in this reservoir provides little resistivity contrast with the shale roof making it very difficult to interpret the upper bed boundary. The ability to interpret the bed boundary is only compensated by the shale anisotropic effect on the propagation resistivity, which is limited to some 1m maximum depth of detection. In addition to the above, insufficient hole cleaning and tortuous trajectory will contribute to high drilling torque that poses a challenge to reach the desired well length. With these multiple challenges, experienced geosteering personnel in this field are an important factor in successful well placement.
The standard practice for geosteering in this field is to use the real time resistivity response and compare it with forward resistivity models to interpret the well position. This had been successfully done by three service companies with experienced geosteering personnel in the ongoing drilling campaign. The standard LWD suite is density, neutron, gamma ray and propagation resistivity. From the propagation resistivity tool, various compensated resistivities are being transmitted in real time and used for the well placement. Gamma ray provides a secondary indicator to indicate if the well is near to the shale caprock.
In conclusion, we are now routinely successful in geosteering horizontal wells in ultra-low resistivity and flank of a flatly dipping structure. This has proved the economic viability of transitional oil column in the flank and thus adding reserves to the field.
Comprehensive Micromodel Study to Evaluate Polymer EOR in Unconsolidated Sand Reservoirs
Authors: Herbas J.G. , Wegner J. , Hincapie R.E. , Födisch H. , Ganzer L. , Castillo J.A. Del , Mugizi Herbert Magyezi 
Published: March 2015

Abstract
In this work micromodels are generated from high resolution images of unconsolidated sands and subsequently used to study polymer EOR processes. Using this approach an almost unlimited number of equal copies can be produced. Moreover, compared to cores, the micromodels enable visual access to the flooding process, facilitating a more detailed process description. Understanding the mechanisms and effects of polymer flooding is essential to avoid failures in field applications. Core studies conducted by commercial laboratories indicated very optimistic oil recovery from polymer injection; therefore, a micromodel study was proposed to investigate the recovery process in detail. The experiments were conducted at reservoir temperature.
This study aims to support the design and optimization of polymer EOR projects by experimentally determining polymer performance in terms of production acceleration, incremental production and reduction of the residual oil saturation. Performance is evaluated for a variety of critical input parameters such as polymer rheology, product, and concentration for different average rock properties. The study includes complete rheological characterization of three polymers in terms of flow curves and, in specific cases, viscoelastic effects. The characterization enables the determination of suitable polymer concentrations based on three predetermined viscosity ratios. During the flooding experiment, the oil saturation changes are continuously monitored through image analysis based on which the recovery factor can be calculated.
Experimental results obtained from corefloods are compared to those obtained in micromodels, focusing on the following key parameters: (1) Recovery factor, (2) injected pore volume at breakthrough time, (3) residual oil saturation. The paper illustrates how the micromodel experiments help to improve the understanding of oil recovery processes during polymer EOR.
The Evolution of Well Testing Practices From Conventional to Zero Flaring in a Saudi Aramco Oilfield Development
Authors: Duthie L. , Arukhe J.O. , Namlah S. 
Published: March 2015

Abstract
Increased concerns from well testing activities about the environmental impact have left several oil industry challenges. Some of these challenges include handling well effluents from flow back operations with sour crude; the challenges can be more severe to contend with H2S safety, pollution and spill risk. Limited deck space in offshore environments often restricts the footprint of flow back equipment. An optimized solution to cater specifically for offshore operations requires careful design to ensure a safe yet functional flow back system. The pollution risk from fall out could have serious consequences to the marine life and habitat. Given that offshore operations typically cost an order of magnitude in excess of land based operations, weather uncertainties could typically result in cost overruns, increasing total job costs.
The scope of the paper is to examine the evolution of well deliverability testing — from conventional flaring practices to contemporary smokeless and zero flaring operations in a giant carbonate oil field in Saudi Arabia, surrounded by a world class environmentally protected marine and coastal ecosystem. The examination of 100 well testing candidates, with 39 of those using the zero flaring approach, allows a demonstration of the clear cost, technical and economic benefits over traditional flaring techniques.
Before the production facilities and flow lines were operational, the previous clean up method required flaring of oil and gas. Although best practices were applied, an environmental and technical cost accompanied the approach. With the completion of the flow lines and production facilities, the application of the zero flaring option became possible. The possibility to conduct zero flaring provides several attractive benefits, with at least the equivalent of 4,000 barrels of oil not flared, pollution avoidance, 50% time saving and over 50% reduction in total job costs for the field development.