bluuebunny/crossref_metadata_2025_split huggingface dataset:
Optimization of a High Fidelity Virtual Model of a Hydraulic Hoisting System for Real-Time Simulations
Authors: Pawlus Witold Pawel , Liland Fred , Nilsen Nicolai , Oydna Soren , Hovland Geir , Wroldsen Torstein Kurt 
Published: March 2015

Abstract
Nowadays, modeling and simulation software enhancing design and development of hydraulic-mechanical drilling machinery becomes increasingly popular in the offshore industry. The current work presents an efficient way to optimize large, high fidelity models of such equipment. First, a complex virtual model of the selected hoisting system is created and compared with the reference data logs recorded on a full-scale rig. Second, rules and guidelines for conversion of a complex model to a low fidelity model which could be simulated in a real-time (RT) environment are formulated.
Typically, a complex model of offshore machinery is suitable only for offline tests. Therefore, to perform RT simulations it is necessary to optimize it. The methodology presented in the current paper provides for interaction with a virtual model in real-time via a full-scale control hardware and software. This in turn allows to perform a hardware-in-the-loop (HIL) test and evaluate developed control systems as well as to verify if chosen control equipment meets the desired performance.
Simulation results prove that both high and low fidelity models yield comparable outcomes which correspond well to the reference real world rig measurements. It is concluded that to simplify a model it is important to determine how its particular components affect computational efficiency of the simulation hardware and to clearly understand functions of the considered machine.
The paper contributes in two areas. Primary - a high fidelity virtual model of an existing hoisting system is established. The simulated model is benchmarked against real measurements from the offshore drilling rig. Secondary - such a complex model is reduced and confirmed to be applicable for real-time HIL simulations. RT performance can be difficult to achieve even on modern computers due to the stiff nature of hydraulic-mechanical models and high demands on computational power.

Introduction
High level of technological sophistication, high price and small production numbers are the features that characterize the offshore equipment produced nowadays. According to Bak et al. (2011), manufacturers of offshore machinery are required to have a high level of experience and skills to design and develop their products due to the fact that normally it is not possible to construct prototypes to evaluate if a new design will work. Consequently, design engineers are constantly challenged to find the best possible trade-off between reliability, capacity, and cost of the produced equipment. Therefore, an increasing attention of the offshore industry is directed towards tools and methods that allow virtual prototyping and simulation of new designs which in turn makes it possible for engineers to test, redesign, adjust, and optimize a solution before it is manufactured.
Revitalisation of South Fawares Field Using Open Hole Multistage Completion Systems – A Pilot Project Case Study
Authors: Al-Najim Abdulaziz A , Al-Harbi Musaad S , Al-Rubaiyea Jamal A. , Al-Mutari Fawaz , Al-Ayyaf Emad A , Hadi Ahmed Abdul 
Published: March 2015

Abstract
Located in the Partitioned Neutral Zone between Kuwait and Saudi Arabia, the South Fawares field has been producing from the Lower Cretaceous Ratawi reservoir since 1956. Several conventional coiled tubing acidizing treatments have been performed to restore productivity from the Ratawi formation. However, due to the formation heterogeneity, limited zonal coverage and inconsistent acid distribution, these treatments resulted in limited improvements to productivity.
The objective of this study was to determine the most appropriate re-completion/stimulation technology that could achieve the following: Effectively and evenly stimulate the entire horizontal section,Benefit from the vast network of natural fractures within the formation matrix to further enhance production, andMaintain wellbore integrity.
This paper presents a successful pilot project implementing horizontal open hole multistage completion systems for the first time in the South Fawares field. Existing lateral sections drilled across the Ratawi formation in the South Fawares field were segmented into several stages and each stage was fracture acidized separately to achieve optimum acid placement and maximize the net stimulated reservoir volume.
The results show that effective wellbore isolation between stages coupled with efficient diversion of the stimulation fluid is key to improved well productivity. This paper highlights the planning, execution and challenges of the installation of these systems with comparisons of pre- and post-stimulation data and offset wells.
The success achieved from the first deployment of open hole multistage completion systems in the South Fawares field has opened new opportunities for reviving the productivity of additional depleted wells.

Introduction
The South Fawares field is situated in the Partitioned Neutral Zone (PNZ) between Kuwait and Saudi Arabia, (Fig. 1), where the natural assets are shared jointly under the Neutral Zone agreement signed in 1922. Since 1949, Saudi Arabian Chevron, a 100% owned subsidiary of Chevron, the Kuwait Gulf Oil Company and their predecessor companies have operated four oil fields in the onshore PNZ. The fields are Humma, South Fawares, South Umm Gudair and Wafra. In 2009, the 60-year agreement between Saudi Arabia and Chevron predecessor, Getty Oil Company was amended and extended for another 30 years. Under this agreement, Chevron operates Saudi Arabia's 50 percent interest and the Kuwait Gulf Oil Company operates Kuwait's 50 percent interest in the PNZ.
Remaining Exploration in the Southwest Malita Graben, Bonaparte, Australia
Authors: Tan H.K. , Jewett K. , Lorage A. , Amiribesheli S. 
Published: March 2015

Abstract
The Malita Graben, situated within the Bonaparte Basin, is highly under-explored relative to similar geologic settings along the North-West Shelf of Australia. The Mid-Jurassic Elang/Plover Formations have historically been the highly successful exploration target across this basin. However, with high reservoir temperatures and deep formation burial within the Malita Graben, reservoir degradation due to quartz overgrowths was considered a large risk at the Jurassic level. In 2011, D-1 and L-1 wells had drilled at the junction of the Sahul Syncline and Malita Graben to test the Elang/Plover play in the block WA. As a result, thick successions of high-quality Upper-Jurassic to Lower-Cretaceous 'Sandpiper' reservoir were intersected. Subsequent seismic, well log synthesis and reservoir characterisation studies have upgraded the potential of Sandpiper sandstones within the Malita Graben, which remain largely under-explored.
The strata penetrated by D-1 and L-1 wells provided key geological evidence to constrain the depositional model associated with the infilling stages of the Malita Graben. The wells intersected thick, homogeneous Late-Tithonian to Early-Berriasian quartzarenite units, encased in pelagic, deep-marine shales. 54m of conventional core was obtained in D-1 well, straddling the Tithonian-Berriasian boundary. The core is considered key as it refines biostratigraphic age dates, gives evidence for turbidite deposition in a deep-basin setting, and reveals a pronounced vertical heterogeneity in permeability readings. Correlating D-1 to L-1 wells suggests coeval stratigraphy, and thus possible lateral connectivity of a sand-rich submarine fan system in the vicinity of Block WA, and possibly in broader regions throughout the Malita depocenter.
The results of D-1 and L-1wells were significant in advancing the understanding of the Sandpiper sand distribution. The occurrence of thick Tithonian and Berriasian sands, which were not expected prior to drilling, opens opportunities for further review of the play in the Malita and Sahul depocenters. However lateral and vertical reservoir heterogeneity of the sands is both complex and challenging to apply to an exploration strategy across the Malita Graben. Modern seismic data may help enhance the understanding of the Sandpiper play in the area, but predicting clay mineralogy and its association with diagenetic processes on individual lobe sequences may remain elusive.

Introduction
The Malita Graben is a prominent depocentre within the Northern Bonaparte Basin and contains up to 10km of Mesozoic to Cenozoic sediments. Previous exploration in the area has been focused on the Middle Jurassic Elang-Plover play, but drilling has been largely restricted to structural highs adjacent to the main depocentres. Limited drilling has been undertaken within the Malita Graben, primarily because of reservoir quality risk sassociated with deeply buried, high temperature reservoirs.
Key Factors Differentiate the Success Rate of Coalbed Methane Pilots Outside of North America - Some Australian Experiences
Authors: Johnson, Jr. Raymond Leslie , Mazumder Saikat 
Published: March 2015

Coalbed methane (CBM) has been considered a relatively mature unconventional gas resource in North America. In Australia, where the CBM or coal seam gas (CSG) industry is nearly two decades old, there have been successful and unsuccessful pilot projects and resources have been slower to develop after nearly twenty-five years since North American technologies were exported internationally. Thus, it is reasonable to believe that there are differences outside North America that have hindered CBM development in Australia.
Often CBM pilots owe their degree of success to one of three major factors: geologic or structural setting, reservoir properties, or completion strategies. Most pilot testing have been conducted either to characterize the production from a particular geo-domain associated with certain perceived geological risk and uncertainty or to estimate potential project reserves to a reasonable degree of accuracy. This need to reduce uncertainty is more pronounced in Australia based on the need to balance development decisions, tenure retention requirements, whilst minimising the risk for the upcoming development phase.
Often in hindsight, the opportunity to increase the chance of success for good areas or reduce the expenditures in poor areas was achievable through improved reservoir characterisation or better pilot planning. In some cases, the resource volumes are large, but the progression of resources to reserves has been less certainty based on challenges. In this paper we will highlight some key observations from several Australian CSG pilots that led to success or challenges for each case. The authors' goals are to identify key indicators, which if recognised earlier may have increased the rate of success or reduced unnecessary expenditures in these pilot areas.
Slickwater Chemistry Concerns and Field Water Management in Tight Gas
Authors: Langille David , Scheck Michael , Seligman Ben 
Published: March 2015

Abstract
The method of stimulation employed at the Shell Groundbirch asset in the Montney tight gas play is the limited-entry slickwater hydraulic fracture. The original fracturing water specification was a simple filtering requirement and an allowable range of salinity. Considering the associated health, safety, security, and environment (HSSE) perspectives, costs, and perceptions with sourcing and disposing of water related to hydraulic fracturing, determining a fracturing water specification became critical. This paper will describe a concise and pragmatic approach for determining a new fracturing water specification and water handling system aimed at recycling flowback and produced water, while using as little fresh water as possible.
This water specification case study is based on the industry considerations of hydraulic fracturing and water management, and their impacts on costs and the environment. This approach to determine a chemistry specification for slickwater hydraulic fracturing and handling considerations may be applied elsewhere to enable the optimization of sourcing and disposal, HSSE concerns, production impairment prevention, and cost reduction.
The process of determining the water chemistry specification assessed bacteria, formation damage, scale, and friction reduction performance. After a year of consultation and experimentation, an improved, but still simple fracturing water specification was established. Chemical use includes a scale inhibitor in addition to the on-the-fly fracturing fluids of a friction reducer, a surfactant, and a biocide. Scale inhibitor usage depends on pH and iron content. Coupled with water chemistry considerations, an integrated team initiated an intrafield water handling system that first recycles flowback or produced water and uses fresh water only when brine volumes are insufficient.
This paper will specifically address (1) a method to develop a water chemistry specification for slickwater fracturing, (2) a pragmatic means of forecasting water in tight gas developments, and (3) a means of integrating water chemistry and forecasting learning into application for pragmatic field development.

Introduction
Tight gas developments rely on hydraulic fracturing to produce gas at economically viable rates. One popular method of hydraulic fracturing is the limited-entry slickwater fracture treatment in which a number of perforation clusters are attempted to be simultaneously stimulated with a slickened water and proppant slurry in a number of stages throughout the wellbore. The implications of water in tight gas beyond hydraulic fracturing have been recognized at Shell Canada's Groundbirch development in the Montney play. Shell Canada's Groundbirch asset is located in Northeastern British Columbia, Canada, per Figure 1. The current land base consists of nearly 400 sections of Montney focused development of which about half are Shell's land held with Brion Energy, while the remainder are held jointly between Shell and other partners.
Permanent Downhole Gauges Selection for HPHT and Fractured Basement Reservoirs, Vietnam
Authors: Pham Hoanh Van , Green Christopher A. , Yapp Christopher , Le Thao Minh , Butt Andrew 
Published: March 2015

Abstract
CuuLong Joint Operating Company, Vietnam operates a number of HPHT and basement fractured reservoirs and has installed over 60 quartz or fiber optic permanent downhole gauges in development wells, since 2003. This paper reviews the selection process for the different type of gauges, gauge reliability and also details some of the considerations when assessing the relative cost advantage of each gauge type.
Equipment and material reliability has always been critical to success in the HPHT and fractured basement environment. As development wells target ever more challenging reservoirs, extreme testing and qualification processes are required to give reliable downhole sensors. This paper describes a methodology used by an Operator to address the significant challenges of selecting gauges for high temperature reservoir monitoring. The work details how the extensive qualification/testing process was successfully applied to select suitable gauges. Initially, after selecting quartz gauges the first deployment of an optical gauge system took place offshore Vietnam in February 2009. To date a total of 20 fiber optic gauges have been installed on different platforms in various reservoirs and when successfully installed have achieved a 100% success rate.
Four major areas were addressed using this methodology, which are necessary in order to ensure success:Establish applicable standards appropriate optical sensing technology to which components should comply, in order to qualify for selection.Determining the reliability of electronic gauge systems in the specified high temperature reservoirs environment.Develop an effective monitoring and optimization process that considers all possible scenarios, in order to properly assess the cost-benefit of the proposed system.Continually review and improve the system based on available data and analyses.
Application of this methodology has led to a 100% success rate for recently installed gauges and application of this system, developed over the past 10 years, should help other operators world-wide achieve similar success rates in comparable, 'extreme' reservoir monitoring environments.
An Evaluation of Various Perforating Designs Performance in Reducing Near Wellbore Friction during Fracturing
Authors: Al-Momin Ali Mansour , Al-Saihati Ali Hussein 
Published: March 2015

Abstract:
Establishing connectivity with the reservoir in a cased-hole cemented completion is a crucial parameter for the success of fracturing operations. Numerous fracture stimulation treatments have failed due to the failure to initiate the fracture or to place enough proppant along the hydraulically created fracture due to an early screen-out caused by improper perforating design. This problem becomes more significant in the case of unconventional resources exploration and development as these resources inherently require a high treatment pressure coupled with a high fracturing gradient. Therefore, a well-engineered perforating design is regarded as the first challenge to be overcome to ensure the success of a fracturing treatment.
This paper presents a comparative study among different perforating guns by different service providers with different sizes in terms of reducing the near-wellbore pressure loss during fracturing treatment. Moreover, various design parameters such as perforation phasing, density and perforating interval were evaluated for several gas wells completed with proponent fracture in a giant field in Saudi Arabia. The comparison is based upon analyzing the step-down rate tests and quantifying the contribution of pressure loss due to entry friction to the total friction during the stimulation. The magnitude of the treating pressure for various designs during the main fracturing treatments was also examined. Reservoirs investigated include tight sand and unconventional gas bearing formations. Different techniques to mitigate or reduce excessive near-wellbore friction are also presented.
Planning infill drilling and workover programmes based on reservoir-oriented production logging surveys
Authors: Aslanyan Arthur , Aslanyan Irina , Karantharath Radhakrishnan , Matveev Sergey , Skutin Vasilii , Garnyshev Marat , Bevillon Damien , Mehrotra Nagendra , Suarez Nelson 
Published: March 2015

Abstract
Wellbore fluid flow profiles in both producers and injectors tend to change over time due to preferential depletion, formation damage, cross-flow, channelling or tubing or casing leaks. These changes can result in excess water production through channelling, coning, non-uniform water breakthrough (fingering) or out-of-zone injection – all leading to uneven flow, pressure and sweep profiles. Ignoring these complications can result in missing key points on reservoir behaviour, selecting wrong units for a 3D full-field flow model or misleading redevelopment planning. Therefore, it would be logical to check for changes in flow geometry before embarking on costly workovers, recompletion or infill drilling programs.
This paper compares and integrates the results of conventional Production Logging Tool (PLT) surveys that use spinners and multiphase sensors with those acquired by reservoir-oriented production logging surveys employing a combination of Spectral Noise Logging (SNL) [1,2] and High Precision Temperature (HPT) Logging [3–5]. PLT and HPT-SNL produce similar results when wellbore and completion conditions are good but they may differ dramatically in cases of non-uniform formation damage, channelling behind pipe or plugging of perforations by scale. Generally, HPT-SNL would assess the flow geometry and invaded zones of the reservoir while PLT would point out where fluid enters or leaves the wellbore or tubing.
The paper provides case studies from a mature offshore waterflooded field producing a mix of oil, gas, formation water and injection seawater, which complicates the identification of flow geometry and invasion zones and represents a challenge for reservoir engineers in developing proper drilling or workover programmes to target residual reserves [6, 7]. The HPT-SNL-PNL surveys and further studies described here led to successful workovers and drilling. The redevelopment results can be easily assessed by decline curve analysis.

Introduction
Since 2007, Dubai Petroleum Establishment (DPE) has performed more than 150 integrated PLT-HPT-SNL surveys to monitor vertical wellbore injection and production profiles that resulted in valuable and often surprising findings including unexpected water breakthrough intervals, bypassed oil zones and layers and water channelling behind casing in producers and injectors. These findings, in turn, led to a better understanding of how water propagated through reservoir from injectors to producers and were used to calibrate a 3D full-field flow model and identify optimum infill drilling locations for the redevelopment of the highly fractured crestal area of the field.
Improved Employee Retention Through Active Engagement and Focused Action
Authors: Raj Reuben D. , Zaid Elfarina 
Published: March 2015

Extended Abstract

Introduction
The company operates a Technology Center to manage new product development, manufacturing, supply chain and product-sustaining activities on the island of Singapore. The Technology Center has an average of 950 employees who are divided into two groups i.e., Exempt and Non-Exempt. The Non-Exempt employees are eligible for overtime pay whilst the Exempt population, made up mostly of office-based staff, are not eligible for overtime. The ratio of Non-Exempt to Exempt staff in this Technology Center averages about 60:40 for the last 5 years.
Since 2009, one of the main challenges faced by the Technology Center in Singapore was the high turnover of employees, especially in the Exempt group.
This extended abstract will describe best practices and lessons learned in the Singapore Technology Center to improve employee retention in the last 2 years.
Based on surveys and feedback sessions, lifestyle and career barriers were regarded as some of the main factors that impacted employee retention.
Various initiatives were conceived and implemented to engage the target population, facilitate active discussion, and improve employee morale and satisfaction at work through focused action.