bluuebunny/crossref_metadata_2025_split huggingface dataset:
A Numerical Study on the Thermal Behavior of Wellbores
Authors: Ferreira Marcus V. , Hafemann Thomas E. , Barbosa Jader R. , da Silva Alexandre K. , Hasan Rashid 
Published: August 2016

Abstract
The thermal behavior of a deepwater well was simulated using an existing mathematical model in which a rigorous flow-pattern based multiphase flow model was employed to predict the pressure drop of the hydrocarbon stream. The heat transfer model relied on the energy equation for the hydrocarbon mixture and on a radial thermal resistance network between the wellbore and the formation. Different annulus convection and thermal formation models were evaluated.
Production pressure and temperature results were compared with field data and with a commercial software package, showing good agreement with both. The model was able to capture important quantitative phenomena associated with the wellbore heat transmission (e.g., lithologic column and annulus fluid type). The simulations showed that for short production times the heat transfer to the formation was significantly influenced by the wellbore thermal resistances, namely the cement sheaths and the nitrogen present in the production annulus. As the production time increased, the formation became the dominant thermal resistance. The mathematical model was capable of handling real production scenarios, such as the impact of a watercut time-dependent behavior on the temperature distribution in the wellbore.
Delayed-Release Acid System for Remedial Cleanup of Well Perla-7
Authors: Cedeño Freddy , Deen Larry , Martinez Juan , Rojas Ybrendiz , Martinez Valentina , Plazola Pedro , Segatto Michele , Martinez Ricardo 
Published: August 2016

Abstract
The Perla-7 well experienced lost circulation while drilling the naturally fractured carbonate reservoir. To cure the losses, 285 bbl of various lost-circulation materials (LCMs) were pumped. This plugged the 300-micron slotted liner and resulted in an impairment of production. This paper describes a study of the solids retention by a 300-micron slotted liner and the design, testing, and application of a delayed-release acid system to remediate the plugged well and recover productivity.
The well was closed while spotting the delayed-release acid treatment; gas was filling the well from the previous well testing. Coiled tubing (CT) was used along with a proven fluidic oscillator technology that enables better control when matching fluid rates to the most desirable frequency and amplitude of the pressure pulses. When the pressure began rising from the last recorded surface pressure, the well was bled off on the surface to maintain a balanced condition. After the treatment, the well was opened and cleaned out using well testing equipment, flaring hydrocarbons, and spent acid.
Logistical considerations resulted in the selection of the in-situ acid-release system instead of conventional treatments. The pumped LCMs dissolved successfully, helping to swiftly recover well productivity. The acid-release treatment was split into two stages, with a 30-minute soaking time between the pumping of the two designed engineered pills. A total of 270 bbl of the delayed-release acid were pumped at a 25% volume/volume concentration. No special tanks were necessary for this operation; the acid-release treatment is neutral on surface and is easily handled until required. The well test interpretation was developed based on a pressure buildup period before and after the treatment. The results returned a fairly good reservoir property, with a Kh of approximately 10 000 md-ft with a consistent skin reduction from 14 to four. There was also a corresponding reduction in the drawdown of 120 psia, which was necessary to achieve the same gas rate of 50 million scf/D.
The Perla field is the largest offshore gas reservoir discovered to date in Latin America. The Perla-7 well was drilled in the Cardon IV block, located in the shallow water eastern part of the Gulf of Venezuela. The in-situ acid release treatment is now an alternative option through which to support offshore operations where logistics can be challenging, especially when well remediation is required.
A Technical Approach for Successfully Drilling Unconsolidated Sands in Critical Applications
Authors: Mahrous Ramy , Elshout Nathan 
Published: August 2016

Abstract
During a drilling campaign in the southern North Sea involving installation of two additional conductors inside a mono-tower, significant challenges to the operator were encountered. The mono-tower is a hydrocarbon production platform with six slots. The slots are located inside the foundation pile, extending above sea level, and were driven into the seabed using an impact hammer. Structural integrity of this foundation pile over the platform operating lifetime is paramount.
The basis of the well is its conductor, which is typically installed using the drill/drive method with an impact hammer followed by soil drillout. Offset installation challenges in the mono-tower deemed using the drill/drive method ineffective for this new well. An alternative method for installing conductors is the drill/grout method. However, drilling an open hole increases the possibility of massive washout or hydraulic fracture. The fluids provider designed a water-based mud (WBM) system customized for rapid fluid-loss prevention, thus strengthening the wellbore, maintaining hole integrity, and preventing hydraulic fracture.
In subsea or conventional platform wells, fluids return at the seabed without additional hydrostatic pressure. Because of drilling inside the foundation pile, the lowest achievable elevation for fluid returns is at the top of the foundation pile. Fluid flow into the formation can lead to degradation of the soil-bearing strength around the single foundation pile and adjacent wells. This could potentially lead to subsidence of the mono-tower or buckling of the existing wells. In case of experiencing ever losses a contingency plan was in place with a decision tree used to determine the most appropriate formulation and sequence of lost circulation material (LCM) pills, with setting cement plugs as a last resort. Installing the two additional conductors with that rig could have impaired the structural integrity of the platform foundation pile. The drilling mud design played a vital role in managing this risk.
The uniqueness of the fluid design helped deliver the section without wellbore instability issues, hence avoiding losses or hole collapse, requiring reactive measures. The results demonstrated that wellbore pressure containment and full hole integrity can be achieved when drilling unconsolidated sands.
The novelty of the technical process and fluid design approach acted as a barrier to help prevent losses and proved the theory of wellbore stabilization and strengthening in unconsolidated sands through field applications.
This paper focusses only on discussing the application of an engineered fluid solution through a rigorous technical approach, which contributed to the success during such critical operations.
Mitigating Salt and Sub-Salt Drilling Challenges Using Hybrid Bit Technology in Deepwater, Gulf of Mexico
Authors: Chowdhury Ashabikash Roy , Callais Ryckman , Rothe Mitchell , Anderson Mark , Koons Brian , Bathgate Grant 
Published: August 2016

Abstract
The deepwater Gulf of Mexico (DW GOM) poses a variety of drilling challenges including subsurface challenges related to drilling through salt, such as salt creep, wellbore instability, inclusions, sutures, and tar that add risks to drilling. The sub-salt challenges include drilling through interbedded formation triggering drillstring vibration, hard and abrasive sandstone and pressure transition.
In most exploratory areas where operators are currently active, the water depth is greater than 4,000 ft. As a result, long drill strings are required which increase the likelihood for drilling dynamic issues. Torsional oscillations, lateral vibrations, and whirl pose the risk of bottom hole assembly (BHA) failure, resulting in an unplanned trip. Drilling through interbedded formations of variable hardness often initiates dynamic instability. If not managed, instability shortens the BHA run life and adversely impacts the success of the operation and exposes rig personnel to additional safety risks.
The majority of deepwater drilling applications require the use of an expandable hole opener in the BHA. Drilling through an interbedded formation with an expandable hole opener increases the possibility of the pilot bit and reamer losing synchronization, causing the reamer to overload, which can result in a premature failure and unplanned trip. Alternatively, having an aggressive hole opener in the BHA with an unaggressive pilot bit can result in whirl and the resultant loss of drilling efficiency or eventual failure. Therefore, it is important to use a bit with managed aggressiveness to ensure the bit and reamers remain synchronized.
The use of polycrystalline diamond compact (PDC) bits often aggravates the drilling dynamic instability because of inherent shearing action and resultant downhole torque fluctuations. The instability compromises drilling efficiency and makes it difficult to synchronize the expandable reamer and pilot bit.
In this case study, the operator addressed the challenges of drilling dynamics, expandable reamer and pilot bit matching issues by utilizing a hybrid drill bit in the 18⅛" x 21" hole sections. The hybrid bit, because of its dual-cutting mechanics, addresses drilling dynamics and reamer synchronization challenges through better torque management and controlled aggressiveness.
This paper presents the successful application of a hybrid bit to address drilling challenges and improve efficiency and penetration rates. It also compares the downhole torque produced by PDC and hybrid bits and demonstrates consistent, linear torque response of a hybrid bit for managing aggressiveness.
In-situ Tensile Strength Testing: Awareness of Variations with Testing Environment
Authors: Li Li , Kellum Matthew , Doan Angela 
Published: August 2016

Abstract
Mechanical performance of cement significantly affects cement sheath integrity and long-term zonal isolation, especially in complex high-temperature, high-pressure (HTHP) wells drilled under challenging operational conditions. A majority of cement sheath mechanical failures are believed to occur in tension rather than compression, which has led to increased focus on cement tensile strength. However, most technical literature related to cement tensile strength refers to testing at ambient temperature and pressure, which does not represent actual downhole conditions. In this study, an HTHP tensile strength testing device is used to measure cement tensile strength in situ at simulated downhole conditions, and these data are compared with measurements gathered at ambient conditions.
In this work, class H cement was mixed with mechanical enhancers, an anti-settling agent, and an anti-foaming agent at 16 to 16.4 ppg. Several mechanical enhancers, including polymeric and fiber additives, were investigated. The cement samples were cured inside the HTHP tensiometer at downhole conditions, and the tensile strength was measured in situ at the same curing conditions.
The in-situ tensile strength results were compared with results from the traditionally used uniaxial method at ambient conditions. The difference between the tensile strength tested in situ and at ambient conditions varied depending on the type of mechanical enhancer. For example, a significant increase in in-situ tensile strength was observed for cement with polymeric additives.
This study demonstrates that testing environment significantly affects the measured mechanical properties of cement, and conventional ambient measurements may not accurately reflect downhole performance. It draws attention to industrywide concerns about developing cement systems with mechanical properties optimized for HTHP and other challenging downhole environments.
A Comparative Assessment of Barite SAG Evaluation Methods
Authors: Zeng Wenqiang , Bouguetta Mario 
Published: August 2016

Abstract
Recognizing the potential for, mitigating, or preventing weight material sag plays a critical role in the safety and success of many wellbore configurations. Accessing hydrocarbon reserves in deeper and ever extending reaches presents new challenges of narrower operating windows and hostile environments (higher pressures and temperatures). As a result, drilling fluids for these applications must possess an elevated degree of barite sag minimization. This paper reviews barite sag testing methodologies and discusses their relationship to field applications.
While it has been demonstrated that wellbore conditions, characteristics of the weight material used, and fluid type were all factors affecting settling rates in any given drilling fluid, there are still discussions on what single evaluation method or test might best qualify its potential to sag.
Various barite sag evaluation methods and techniques have been developed, used, and some even recognized as industry standards to assess the potential of weight material settling in drilling fluids. Because of the increasing variety of evaluations methodologies, it is timely to review the relationship between these actual laboratory measurements and field engineering of drilling fluids to recognize the potential for, minimizing, and managing weight material sag.
In this review, synthetic-based drilling fluids engineered to exhibit various types of rheological profiles were tested using a variety of methodologies for dynamic and static weight material settling. Relationships between the composition, rheological properties, and predisposition of the fluids tested to sag were established.
While the data from the tests detailed in this paper suggest clear differentiation between the key properties that most affect static and dynamic settling, the interpretation regarding the selection of a particular testing methodology were more subtle. It was observed that some of the results correlate better with actual wellbore conditions in which either static or dynamic sag would occur than with common drilling fluids engineering best practices. It was also confirmed that sag remains a very complexe phenomenon with a multiplicity of variables making it challenging to indubitably qualify the sag potential with just one single laboratory test.
Deepwater Well Control: Integrated Simulation for Risk Management
Authors: Golding Fritz , Spath John , Newhouse Bob 
Published: August 2016

Abstract
As deepwater drilling leapt into the dynamic positioning (DP) era, many drilling contractors and operators lacked an evidence-based approach for identification of potential process safety and well control failure points. Noble Corporation, a global offshore drilling contractor, (the Company or the Drilling Contractor) has undertaken a journey to scrutinize all critical aspects of deepwater well control operations to ensure a more robust understanding of well issues, operational procedural adequacy, well control intervention practices, and human factors. The Company will present the process and learnings from more than a dozen fully simulated deepwater well control exercises to increase the knowledge base and understanding of the entire industry.
In early 2015, the Company started a program of fully integrated deepwater DP drilling simulation exercises. Utilizing state-of-the-art, immersive simulations with linked software, the Company brings drilling, marine, and engineering crews together with shore based managers from both operator and drilling contractor. Multiday exercises, built on adult learning principles, confront the crews with life-like well control, weather, and equipment failure scenarios that implicate hydrocarbon containment in a deepwater well. All drilling controls are exactly replicated for each vessel, so the drill crew members are in their "native environment," seeing the same drill floor and human-machine interface as at work. Likewise, the DP and power management simulators are the same equipment found on Company vessels. Uniquely, the drilling, DP and power management software is integrated, so that faults on one system impact the others. Beyond the simulations themselves, the simulation center contains all telephone and radio communications and ship-to-shore, enabling the crew to communicate as though they were on the rig; likewise, the shore based rig management and operator drilling engineers participate via telephone. The exercise is facilitated from a high-tech control room with audio, video and instrumentation feeds, and two-way communications. Expert facilitators control events and role play additional players. The lifelike exercises are recorded and a full after-action-review debrief is facilitated with the crews afterwards to identify learnings and opportunities for improvement.
The result of the integrated deepwater DP drilling simulation exercises is a proactive, behavior-based risk management process with the operator and drilling contractor. The exercises return critical learnings and observations in five key areas: Procedural knowledge for critical operations (e.g., well-specific operating guidelines, well control manual, bridging documents)Observed behaviors around well control and loss of position scenariosHuman factors, including team dynamics, relationships, and trustEnhanced situational awareness and crew communicationsFurther training and operational procedure development opportunities
Placing Cement Plugs up to 6,500 ft in Length through the Use of Sacrificial Pipe in Deepwater Environments
Authors: Santiapichi Jorge , Febbraro Anthony , Fuller George A. , Dooply Mohammed , Elhancha Anouar , Martell Ben , Rabei Rob 
Published: August 2016

Abstract
Cement plugs are set for various objectives: to plug back a zone or a well, sidetrack above a fish or initiate directional drilling, protect a low-pressure zone during a workover treatment or solve a lost circulation problem.
It has been demonstrated that more challenges are sometimes found during the design and execution of a cement plug job than that of a primary cementing job, and thus its complexity and criticality of key steps should not be underestimated. Setting of cement plugs in open hole has historically been a challenging and expensive operation when a well is being abandoned.
Current industry habits and practices avoid setting balanced cement plugs over 800 ft. However, advances in cement plug placement procedures, hydraulics modeling and cement slurry testing have notably increased the rate of success of longer plugs, which has encouraged drilling operators to set balanced cement plugs over 1,500 ft.
If the objective is to place a plug over 1,500 ft, multiple cement plugs are typically placed due to concerns of plug quality and getting the workstring stuck while pulling out. The cost associated with such successive operations may represent millions of dollars in a deepwater environment even when the operation is performed with no operational failures.
To minimize the costs, several plug placement methods have been explored by many oil and gas operators to set long cement plugs, with the use of mechanical or hydraulical disconnect tools and sacrificial pipes identified as one of the most feasible options.
This paper reviews the engineering considerations to minimize operational risks and plug placement design challenges when sacrificial pipes are used. Field examples are analyzed in this paper, detailing first an unsuccessful case from which valuable lessons were learned, and successful cases including what is considered as one of the longest openhole plug and abandonment performed in a single job in the industry: a 6,500-ft sacrificial stinger cement plug.
Phosphorus Uptake by Potato from Fertilizers Recovered from Anaerobic Digestion
Authors: Collins Harold P. , Kimura Emi , Frear Craig S. , Kruger Chad E. 
Published: August 2016

The rising costs of fertilizers have encouraged the development of technologies to recover nutrients from dairy, cattle, swine, and poultry operations. Field experiments were conducted in the Columbia Basin of Washington to assess the yield of potato (Solanum tuberosumL.) to application of P‐enriched materials recovered from anaerobic digestion of manure. Four rates of P from five sources, three recovered from anaerobic digesters (AD), AD‐dairy P‐enriched fine solids (ADD), AD centrifuged poultry solids (ADP), and AD dairy struvite‐P (ADS) compared to a commercial poultry fertilizer (PBP) were compared to mono‐ammonium phosphate (MAP) and non‐amended control (No‐P). Fertilized treatments had higher yields than the No‐P treatment. Phosphorus source and application rate had significant effects on petiole P concentrations. Increases in petiole P concentrations averaged 300 to 500 mg kg−1tissue with each rate increase for MAP and ADS. Tuber yields among P fertilizers and rates of P application were not significant but were different between years, averaging 2 and 10 Mg ha−1fresh weight higher than the No‐P treatment. Tuber size distribution showed a significant shift from smaller tubers <170 g to the 285+ g tuber classes. The P recovery efficiency averaged 42% among treatments receiving 56 kg P2O5ha−1and declined to 22% for higher rates of ADS, ADD, and MAP. Recoveries were lowest for poultry derived materials, ranging 20 to 30%. The P fertilizer sources evaluated performed similarly when equal rates of P were applied and method of application was comparable.Phosphorus recovered from anaerobic digesters can effectively substitute for commercial mined P fertilizers.Potato yields among recovered P fertilizers and rates of P application were not significantly different.Recovered P fertilizer performed similarly when equal rates were applied and method of application was comparable.
A Half Century of Changes in Soil Taxonomy
Authors: Rabenhorst Martin C. 
Published: August 2016

Core Ideas
This is the first comprehensive documentation of changes to Soil Taxonomy.
Changes to the higher taxa in soil taxonomy have been irregular.
Four periods during its development had distinctly different trajectories.
The Seventh Approximation emerged in 1960, and the first edition of Soil Taxonomy was published in 1975. Through the years, as intended in its original architecture, revisions have been made at all levels in the system. This has resulted in the addition of two new orders and a multitude of classes at other categorical levels. Four distinct and contrasting periods can be identified and described with regard to the magnitude of changes in taxa at various levels. The most dramatic changes occurred between the mid‐1980s and publication of the second edition of Soil Taxonomy, when numerous international committees that had been charged with investigating particular taxonomic questions were completing and publishing their final reports and findings. Not surprisingly, most of these revisions resulted in the addition of taxonomic classes, although occasionally (especially in the 1998 Keys to Soil Taxonomy) there were notable reductions in the number of classes within certain orders. This review documents the nature and magnitude of changes that have occurred in the development of the US soil taxonomy during its 54‐yr history to provide a context within which to better understand how the current state of our soil classification system has evolved.