bluuebunny/crossref_metadata_2025_split huggingface dataset:
Available Methodologies Concerning the Treatment and Removal of Sand From Pipelines and Associated Case Studies
Authors: Mackay Neil 
Published: March 2015

Summary
Traditional sand-management programs usually consist of several measures employed to mitigate the production of sand from wells, a process commonly referred to as sanding. Such systems include production prediction and monitoring, topside management, sand control, and "intelligent" systems (Gherryo et al. 2009). Sand control can be considered in terms of short- and long-term solutions; examples of long-term solutions (preventative measures) would be the application of gravel packs, screens, inflow control devices, and chemical stabilization methods (Abney et al. 2007). In instances where a sand-management program has not been employed or has been ineffectively delivered, sand can and is deposited in pipelines/riser systems. This can be a gradual process of continual minor deposition over time, or systems can be overwhelmed with a sudden influx of sand as a consequence of formation or completion failure. The result leads to increasing pipeline resistance, reduced flow rates, rising pressure drop in the pipeline system, and erosion, which, in turn, can lead to degradation of the pipeline/riser and topside systems (Abney et al. 2007). The main focus then concerns the short-term sand-control solution of remediating the pipeline system with the goal of removing the deposits. An operator might wish to pursue a sand-removal/cleaning program with the specific goal of performing an in-line inspection as part of an integrity-management scheme.
This paper discusses the available methodologies for remediation of a pipeline affected by sand and presents examples where the discussed methodologies have been applied.
Experimental Study on Wax-Deposition Characteristics of a Waxy Crude Oil Under Single-Phase Turbulent-Flow Conditions
Authors: Swivedi Priyank , Sarica Cem , Shang Wei 
Published: March 2015

Summary
Crude oil, having a paraffin nature, has been studied extensively in the small-scale flow loop at Tulsa University Paraffin Deposition Projects (TUPDP). The effects of turbulence/shear and thermal driving force on wax-deposition characteristics were experimentally studied using a waxy crude oil from the Gulf of Mexico. The test matrix consisted of a total of 15 experiments, which included 12 short-term tests and three long-term tests. The tests were conducted under different operating conditions with a wide range of Reynolds numbers from 3,700 to 20,500. The shear stress ranged from 5.4 to 53.9 Pa.
It was observed that paraffin deposition is highly dependent on the thermal effective driving force, which is the temperature difference between oil bulk and initial inner pipe wall, and also on turbulence effects. The deposit thickness obtained using both the pressure-drop method and a direct measurement was found to decrease with increasing shear stress and decreasing thermal driving force. The wax content showed a gradual increase with an increase in flow rate. For the short-term tests, the deposit mass with no entrained oil seemed to increase and then decrease with an increase in initial shear stress and decrease in effective thermal driving force, whereas the total deposit mass was found to decrease with an increase in initial shear stress or decrease in effective thermal driving force.
Reassessment of Multiphase Pump on Field-Case Studies for Marginal-Deepwater-Field Devolopments
Authors: Abili Nimi , Kara Fuat , Ohanyere Ifeanyi J. 
Published: March 2015

Summary
Subsea-processing technology (SPT) is one of the frontier tools currently being explored by the oil and gas industry to open new opportunities and achieve more-effective exploitation of offshore oil and gas reserves. Exploration and production has moved into unlocking reserves that are less attractive and in difficult environments (e.g., marginal deepwater fields). These marginal fields are located remotely offshore and require one form of processing or another before they can be productive commercially. This paper focuses on the applicability of SPT employing multiphase pumps (MPPs) to develop marginal fields commercially. This was a result of the technology selection established by a comparison of performances of several SPTs for effective development of marginal fields using tools [e.g., quality function deployment (QFD)], and evaluated further using an analytical hierarchal process (AHP), resulting in the most effective innovative SPT for marginal-field development. The result from these tools was validated further in their applications to real-life fields, and this is achieved by specific field-case simulation studies using the OLGA transient multiphase flow dynamic model program to comercially develop marginal fields.
Improved Paraffin-Deposition-Profile Estimation in Hydrocarbon Pipelines and Effective Mitigation Review
Authors: Sheikh Mohammad Samiur Rahman , Chacko Sibi 
Published: March 2015

Summary
Flow of paraffinic hydrocarbon liquids within extended pipeline networks orwells, where the environment/bulk temperature is below the cloud point orwax-appearance temperature (WAT), could result in precipitation of wax from thebulk fluid. Precipitated wax crystals from crudes deposits on the inner pipewall could lead to reduced flow area or even complete blockage and couldpresent a costly problem in the production and transportation of petroleumproducts. Timely removal of such deposits is extremely important to avoidassociated problems. This paper illustrates a numerical approach to estimatethe deposition profile and its effect on flow-related parameters. Later, theprocedure is validated with field data from a North Sea offshore productionfacility. This paper also seeks to propose a feasible solution to avoid suchflow-assurance issues; in doing so, current commonly practiced reduction andpreventive methods are reviewed. Previously, providing thermal insulation withaerogel foam had proved to be the most effective option in preventing wax fromprecipitating. A relatively new approach is discussed in this paper, whichallows for minimizing the usage of insulation material in an attempt to reducethe implementation cost of the proposed precaution. Theoretical implementationof the procedure was also conducted to identify its effectiveness, which waslater found to be elimination of the deposition completely.
Optimization Study of a Novel Water-Ionic Technology for Smart-Waterflooding Application in Carbonate Reservoirs
Authors: Yousef Ali , Ayirala Subhash 
Published: March 2015

Summary
Injection water with selective ionic content and composition is a key requirement for smart-waterflooding (SWF) application in carbonate reservoirs. Smart water--depleted in monovalent ions, but enriched in sulfates and divalent cations--is desired for incremental oil recovery in carbonates, which constitute complex water chemistry when compared with sandstones. Most of the published work available in this area is focused on addressing water-chemistry requirements for low-salinity waterflooding in sandstones. However, none of these studies describes the complex injection-water requirements of SWF in carbonate reservoirs. Also, injection-water chemistry has a known impact on several tertiary enhanced-oil-recovery (EOR) processes among the three major categories of chemical, gas, and thermal EOR. The main purpose of this study is, therefore, to identify and optimize a novel water-ionic technology that can serve as a “one-shop solution” to generate desired water chemistries suited for different improved-oil-recovery (IOR)/EOR processes, including SWF in carbonates. A novel water-ionic technology, comprising nanofiltration and reverse-osmosis membrane-based processes, was identified for optimization in this study. The proposed technology makes use of these two membrane-desalination processes in parallel configuration to provide multiple water streams of widely varying ionic strength and content. Different water streams obtained from this novel solution can be blended effectively to yield a smart-water cocktail of desired ionic strength, composition, and monovalent- to divalent-ion content suited for carbonates. Smart-water cocktails obtained from the proposed solution are also suited for application in other EOR processes such as polymer flooding, alkaline/surfactant/polymer flooding, low-salinity surfactant flooding, dilute surfactant flooding, carbonated waterflooding, and miscible gasflooding, and are suited for boiler feedwater in steamflooding. The optimized scheme thereby offers a novel one-shop solution to meet the complete suite of desired water-chemistry requirements for different IOR/EOR processes. In addition, comparative evaluation-study results between novel water-ionic technology and other already-known advanced-desalination schemes highlight the major advantages of the new solution in terms of better water-ion-tuning flexibility, higher recovery efficiency, lower energy requirement/footprint, and ease of operation.
Multifaceted Approaches for Controlling Top-of-the-Line Corrosion in Pipelines
Authors: Frenier Wayne W. , Wint David D. 
Published: March 2015

Summary
This paper reviews the mechanisms of initiation and the prevention of top-of-the-line corrosion (TLC). Practical, multifaceted techniques based on the most recent research and developments will be described and then illustrated with documented sources to arrive at the best practices for control of this significant corrosion manifestation. The rapid expansion of the production of oil and gas from unconventional sources requires the annual construction of thousands of miles of new pipelines, which will experience a bewildering and changing range of conditions that will require the use of new and innovative internal-pipeline-corrosion-protection methods that have been tested in field applications. These new corrosion-protection methods will be needed because of the complex corrosive environment of multiphase- and stratified-flow pipelines (including gathering lines), which is frequently observed in new shale-play production. Conventional corrosion-inhibition methods (continuous or intermittent injection) may not be effective for inhibiting the pipelines because physical contact of the inhibitors is difficult to achieve in multiphase flowing systems at the top of the line (TOL). In addition, the pipelines must be piggable to be cleaned and treated properly, and traditional slug- or continuous-treatment methods have been found to be less than adequate where conditions exist for TLC to occur. Several innovative methods are being developed to provide effective and long-lasting protection to the entire pipeline surface, including the use of pig trains with inhibitor slugs, improved inhibitor chemistries, inhibitors added to gels and foams, and special pigs that provide a 360° spray of inhibitor chemicals. The newer methods will be compared with the older technologies.
Innovative Solutions Enable Production Start of China's First Marginal Subsea-Tieback Oil Field
Authors: Jiayou Mao 
Published: March 2015

Summary
Liuhua4-1 (LH4-1) oil field is located 215 km southeast of Hong Kong in the South China Sea. The field was first discovered in 1987, but because of economic and technical challenges, it was not until 2012 that the development of this field became a reality. The 300-m-water-depth oil field was successfully tied back to an existing oil field [Liuhua11-1 (LH11-1)] through subsea pipeline, power cable, and multiplex control umbilical. The project executions included disconnection, life extension, and reconnection to the existing oilfield floating-production system (FPS). It was also China's first tieback subsea development project. To develop this marginal oil field, a number of technical challenges were overcome through a series of new technologies, and their successful development and implementation.
Study on Severe Slugging in an S-Shaped Riser: Small-Scale Experiments Compared With Simulations
Authors: Park Sangmin , Nydal Ole Jørgen 
Published: March 2015

Summary
Severe slugging is a transient multiphase-flow phenomenon that can occur in pipeline-riser systems, particularly in offshore production of oil and gas. It is characterized by large pressure fluctuations at the base of the riser and is accompanied by fluctuations in fluid delivery from the top of the riser. This unstable phenomenon is undesirable because production and equipment are affected adversely by the large pressure and flow-rate fluctuations. In this study, air-/water-flow experiments have been carried out at the S-shaped-riser facility in the multiphase-flow laboratory of the Norwegian University of Science and Technology (NTNU) and have been compared with results from a flow simulator (OLGA). The results obtained in the work show that stability maps, pressure amplitudes, and slug frequencies are in acceptable agreement with each other; however, some deviations are seen regarding the slug frequencies at low flow rates.
Barzan Onshore-Gas-Facilities Construction: Attaining Excellence Through a Comprehensive SHE&S Management System
Authors: DeHart Robert E. , Brand Johnny 
Published: March 2015

Summary
The Barzan Onshore Project is being developed by Barzan Gas Company Limited, a joint venture between Qatar Petroleum and ExxonMobil Barzan Limited, with RasGas Company Limited (RasGas) assigned to develop and operate the facilities upon completion. The engineering, procurement, and construction (EPC) work is being carried out by JGC as the primary contractor. JGC has subcontracted the construction execution of the work to eight major subcontractors. The project achieved 131 million man-hours without a lost-time incident from July 2012 to March 2014. The workforce peaked at more than 29,000 (or approximately 30,000) persons from multiple countries. This paper describes the overall safety, health, environment, and security (SHE&S) management system as a three-tier model based on the EPC contract in which there are 211 SHE&S contract-related deliverables (in eight general categories) that are measured monthly by means of the SHE&S work-activities schedule. The system pertains to all parties (i.e., RasGas, JGC, subcontractors, vendors, suppliers), and this rigorous monthly accounting helps drive overall SHE&S performance. The contract combines a highly prescriptive and goal-setting approach. The project has a strong leadership team, which has exhibited daily visible commitment to SHE&S from project outset and has solidified the success of the program. Care and concern for the welfare of workers have been top priorities for the leadership team. The systematic approach combined with the leadership team's efforts has delivered a great foundation on which to build and sustain SHE&S performance at site.
Slickline/CTU Deployed Scab Liner System Eliminates Use of Workover Rigs and Reduces Cost
Authors: McLeod J. , Brown M. J. , Diller C. , Harris R. 
Published: March 2015

Abstract
A new rigless stackable pipe system has been developed for running scab liners in damaged production liners or for improving well conformance. The system is designed to be lubricated and run through tubing under pressure and has been successfully deployed in Alaska. This paper details the development, testing and a field trial of this scab liner system. This system has a connection that snaps pipe sections together and is unique in that it allows a much larger internal diameter than other stackable systems. For regions where rig workovers are expensive such as offshore or the North Slope, using the stackable system for scab liners can save up to 90% of the cost of a rig workover. The snap latch pipe is deployed with a combination of slickline and coiled tubing for scab liners. The snap connection is available for use with 2-7/8″ and 3-1/2″ base pipe. Slickline sets a float assembly with a releasable anchor in the tubing then stacks the sections of float equipment and pipe for the required length of the scab liner. The final slickline run is to set a sleeve with a profile and polished bore for coiled tubing operations. Coiled tubing then picks up the entire scab liner and shears the anchor, then runs the liner to depth. On the second run, coil cements the liner in place. A field test of the system was performed in a well with a few sections of pipe prior to deployment in a well for an actual intervention. The target well for the intervention was an injection well on the North Slope. The well had a thief zone that was taking too much injection water and conventional cement squeeze techniques were unsuccessful at shutting off the thief. A cemented scab liner was proposed to isolate the thief zone. A 557′ scab liner was successfully deployed and cemented in place. Target intervals were perforated and the well was put on injection. Details of the design, testing and deployment of the scab liner are outlined in this paper.
Coiled Tubing Intervention Riser System
Authors: Courtois Coy , Mebarkia Sid 
Published: March 2015

Abstract
Chevron's portfolio of subsea assets in the Gulf of Mexico is poised to more than double in the next 5 years starting with First Oil of Jack/St. Malo, the development of Buckskin Moccosin, and the expansion of its exisiting Tahiti and Blind Faith subsea development assets such as Tahiti 2 and Blind Faith 2. Subsea well recovery rates typically underperform when compared to their surface well counterparts. One significant factor is the relatively high access costs for subsea well intervention. Without frequent intervention to maintain well performance, a lot of barrels are left behind. At Blind Faith Chevron is investigating platform-based intervention alternatives that dramatically improve economics by reducing or eliminating the need for vessel-based intervention. A key enabler is the Coiled Tubing Intervention Riser (CTIR) system that creates a direct vertical access point to the flowline riser from the platform. With the flowline accessible by coiled tubing, services such as acid stimulation, artificial lift, hydrate remediation, etc. become feasible. The reach of the coiled tubing is limited to the pipeline end terminations of the riser flowlines making direct vertical access to the subsea trees still a job for the large, expensive vessels. The CTIR system does not replace the need for vessel-based intervention, but it does support some well intervention options.
Extending Coiled Tubing Frontiers to Ultradeep, High-Pressure Well Interventions in Deepwater Gulf of Mexico: A Technical Feasibility Study
Authors: Rudnik Alexander , Nava Carlos Alberto , Grunichev Renny Alexis , Gortmaker Travis , Nwabuzor Charles 
Published: March 2015

Abstract
Coiled tubing (CT) is a well-established well intervention technique in deep water (1,001–4,999 ft [305–1,523 m] water depth) offshore environments in the Gulf of Mexico (GOM). Wells as deep as 25,000 ft [7,620 m] measured depth (MD) are routinely accessed, serviced, and abandoned with CT at the present time. However, as demand for oil and gas continues to increase, the industry is now expanding its activities into ultradeep waters (water depths greater than 5,000 ft [1,524 m]), ultradeep reservoirs (well depths greater than 30,000 ft [9,144 m]) and high pressures (maximum shut-in pressures close to 15,000 psi [100 MPa] at the seafloor and greater than 10,000 psi [69 MPa] at surface). Ultradeep water projects are becoming central to the overall deep water investments being made by the major oil & gas operators, with several projects slated for 2015.
Coiled tubing is considered one of the critical contingency operations that may be required during the completion of these ultradeep high pressure wells. CT interventions are also expected to be part of future well workover/maintenance operations. The extreme downhole and surface conditions that exist in these ultradeep high pressure wells pose many significant challenges to the CT industry, as it strives to provide safe and reliable access to these wells. In order to address some of these challenges, the CT industry has to re-evaluate various aspects of its coiled tubing design and operations, including the minimum yield stress of the pipe material, surface equipment, downhole tools, fluids, and wellbore access modeling software in order to identify any technology gaps that may affect its ability to effectively service these ultradeep, high-pressure wells. Once these gaps have been identified, they must be converted into specific action items to be addressed by all parties, ranging from service companies and equipment manufacturers to operators.
This technical feasibility study on coiled tubing deployment for an ultradeep high pressure project in the GOM describes the evaluation criteria used, identifies technology gaps and outlines the specific solutions proposed.
Preparing For CTD Success
Authors: Ross M. , McLaughlin S. , Milne J. , Diller C. , English C. , Harris R. 
Published: March 2015

Abstract
CTD (Coil Tubing Drilling) has become a mature and successful technology in the continued development of the northern Alaska oilfields. Driven by advancing existing product limits and embracing new technologies, this paper details the development of a new completion technology that allows the operator to plan for and place pre-determined casing exit points within the wellbore to be accessed in the future as the well matures. This new technology addresses many of the typical limiting factors faced by operators when identifying future CTD candidates by reducing the typical preparation time, costs, and equipment limitations currently available to them.
The paper will show the viability and flexibility the operator gains by incorporating the use of pre-determined and spaced outer wedge assemblies affixed to the outside of the production tubing joints and run during the completion phase. The operator has the flexibility to run as many outer wedge assemblies as needed, based on their future field development strategy without imposing limitations on primary completion access or drainage capabilities. When required, an inner wedge assembly is then run and positioned within the outer wedge assembly, using a common wireline set tubing plug as a false bottom no-go. Orientation of the inner wedge is at the operators' discretion. The milling assembly will first mill through the production tubing before being deflected by the outer wedge assembly to then mill through the production casing. Details of the design, testing, and implementation of the system and components will be detailed within the paper.
This technology allows operators to plan for the life of the well at the completion phase. This reduces CTD preparation costs, provides simplified zonal isolation flexibility, and allows upper zones to be exited first if required. The technology reduces the risks and cost of dual string exits, while removing the need to leave an exposed large bore casing/liner at the exit point that could create difficulties during CTD drilling. Future advances and optimization of completion designs are expected to provide a cementless CTD liner completion while retaining zonal isolation capabilities within the wellbore.