bluuebunny/crossref_metadata_2025_split huggingface dataset:
Impact of Digital Slickline Capability on Slickline Conveyance Phases of Plug and Abandonment Operations
Authors: Murchie Stuart W , Billingham Matthew Edward , Esponge Chuck , Guillot Douglas 
Published: May 2013

Abstract
Slickline often plays a vital role in offshore plug and abandonment (P&A) operations, either used in the phases of the operation that require slickline conveyance, or because logistical, footprint, operational, economical, environmental or regulatory parameters of a P&A operation necessitate full reliance on this small, light, cost-effective conveyance offering.
Today's evolving regulatory requirements are leading to an increasing demand on the scheduling and design of P&A activities. For activities such as barrier placement, proof that the work is being carried out to the prescribed high quality is increasingly required both by the operators and the authorities. In addition, as the time, costs, and risks involved in carrying out an offshore P&A operation are considerable, possible savings and risk reduction are highly sought after by the customer.
P&A activities such as perforation, punching, cutting, device setting, and cement placement, previously done by electric line or with memory-based tools which required additional runs in the well and provided only post-job QC, can be carried out by digital slickline without any compromise to the efficiency and immediate certainty of the operation. Conducting these P&A activities with digital slickline enables efficiencies through equipment and logistics simplification, and people and equipment rationalization, as well as reductions in marine support requirements.
Time and cost savings and process risk reduction or elimination, important in their own right on a single well abandonment operation, are increasingly relevant when applied on a full field abandonment scope of work. In addition, the suitability of slickline conveyance in such environments as riserless intervention P&A operations (negating the need for grease injection pressure seal), is another important feature that is part-and-parcel of a digital slickline operation.
This paper will demonstrate, through actual field examples, the use of digital slickline's inherent surface read out and command and control capabilities, the operational value of precision and clarity delivered in real time, and the specific P&A job recordability and capabilities that have been absent from slickline operations of past. Also highlighted are digital slickline's facilitation of personnel and equipment reduction, and subsequent reduction in HSE exposure.
Deepwater Dry Tree Semi Technology Readiness: Perspectives of Operator and Classification Society
Authors: Lu Jenny Y , Lee Ming-Yao , Huyse Luc , Hansen Vigleik L. , Viteri Martha 
Published: May 2013

Abstract
Recently the offshore industry has shown an increased interest in developing a competitive Dry Tree Semi (DTS) concept. Several DTS designs have been proposed by floater designers and many of them have been evaluated by Operators and Classification Societies. So far, no DTS has been selected as host platform for a deepwater field development project.
A Dry Tree Semi can be utilized for both drilling and production, eliminating the cost of the MODU which can run at approximately USD 500,000 per day and higher for ultra deepwater fields. Once a discovery is made, the field is no longer dependent on the MODU market for drilling access. The DTS concept increases the potential for deepwater development, especially for marginal fields. The result is increased reserves and productions in the Gulf of Mexico. It is essential to ensure that proper qualification of the concepts and all systems/components with novel technology has been carried out, in order to establish the foundation for a safe and successful project implementation, and reduces potential risk on personnel, environment and property.
This paper provides an overview of the current technology and the concepts needed to be matured in order to make the project ready from operators and Classification Societies perspectives. The paper will discuss the key technical challenges of the DTS concept in general and how to make this technology ready to implement. Key technical issues discussed in this paper are global performance of the floater, riser system and responses, tensioner capabilities as well as technology qualifications. The paper will make relevant comparisons with other competing floating systems like TLPs, FPSOs and spar units.
The methodology recommended to be utilized for the evaluation of the DTS technology is based on Chevron's Project Development & Execution Process. Within this process there is a Technology Selection workshop where the necessary technologies for the project are identified and determined as, enabling or enhancing, engineering or technology, and " proven technology?? or " new technology??. The " new technologies?? are then evaluated through the Technology Qualification Process. The Chevron's TQ Process was co-developed with DNV and is based on DNV-RP-A203 " Qualification Procedures for New Technology??.
Design Method Combing API and ASME Codes for Subsea Equipment for HPHT Conditions Up to 25,000 psi Working Pressure and Temperature to 400?
Authors: Taylor Samuel L , Kocurek Chris George , Pathak Parth Dilip 
Published: May 2013

Abstract
A current challenge in the oil industry is the design of subsea equipment for pressures more than 15000 psi and temperatures more than 250°F. This combination of pressure and temperature has been fairly accepted as the start of the HPHT region.
Current standard, American Petroleum Institute, Specification, 17D (API 17D) for designing subsea equipment is limited to 15000 psi working pressure and provides little guidance on temperature conditions above 250°F. This paper demonstrates a design methodology which combines the API and American Society of Mechanical Engineers (ASME) Boiler and Pressure Vessel Code (BPVC) for designing an example subsea pressure containing component for HPHT conditions above 15000 psi and with temperatures more than 250°F. This paper shows the evaluation of combined load capacity chart for an API 17D (API 6A, 4?? 20K) flange flow-loop for design pressure of 20,000 psi and temperature of 350°F with external tension and bending loads. Both the linear elastic and elastic-plastic methods for protection against plastic collapse are used to determine the structural capacity of the flange body. These methods combine the API material and design allowables and ASME design methods. Stress classification and linearization are used for the evaluation of design capacities with linear methods. Modified Load Resistance Design Factors are used to both evaluate design capacities and to account for the difference in ASME and API hydrostatic test pressures with elastic-plastic methods. The structural capacity is combined with thermal analysis to determine the effects of high temperature to the flange capacity. To assess the cyclic loading capacity of the flange, stress-based fatigue analysis and fracture mechanics analysis are also compared. The results obtained are comparable to existing API TR 6AF1 charts. This work has been performed to demonstrate both the acceptance of existing methods for HPHT conditions, but to also introduce the advanced ASME design methods for designing API 17D subsea equipment. The methods presented are acceptable for designing equipment up to working pressures of 25,000 psi and temperatures up to 400°F.
Rigless Repair of Subsea Tubing Leaks Using Pressure-Activated Sealant
Authors: Humphrey Kathryn J , Chambers Michael J , Huebel Ross M , Cary D. Neil 
Published: May 2013

Abstract
BP policy specifies requirements for well barrier management throughout the life cycle of a well. Well barriers are specifically required to isolate energy sources within the earth from each other, the surface environment, and people. Annulus pressure management is fundamental to maintaining healthy well barriers and active monitoring assures the barriers are in place. In subsea wells, the only annulus that can be monitored in real time is between the tubing and production casing (aka A-annulus). When an anomaly is detected in the A-annulus, then a diagnostics and intervention program must be implemented to repair the suspected well integrity issue. In deepwater environments, repairing a well integrity issue with a rig can be costly and the traditional tools for well diagnostics and repair, such as wireline and coil tubing, are complex to deploy into subsea completions. Alternatives such as pressure-activated sealants have a proven track record repairing well integrity issues in dry tree wells. This technology is now being deployed to repair well integrity issues in subsea wells.
This paper presents two case studies where pressure-activated sealants were used to successfully repair tubing by A-annulus (T × A) communication in a subsea wells. BP had utilized this technology with great success in its Alaska fields (SPE Papers10895 and 120978) and saw an opportunity to extend those learnings to subsea wells. These operations utilized innovative delivery techniques to enable sealant injection, placement, and activation downhole. Rigorous testing, simulation, and planning prior to starting the job increased confidence in the operational technique and reduced safety risks to the environment and the wells. Both efforts resulted in a successful repair of the well integrity issue.
There were several benefits for using a pressure-activated sealant for these two interventions. The less complex non-rig interventions presented fewer safety and environmental risks and were completed with no HSE incidents. The non-rig repairs were completed for a small fraction of the cost of a conventional rig repair and rig time was kept available for drilling and completing new wells. Given its effectiveness and these benefits, the application of this technology may be especially useful for subsea wells with marginal remaining reserves where the relatively lower cost may help to optimize productive life and ultimate recovery. The integrity of a sealant repair can be monitored during the life of the well just like a conventional rig repair and a sealant repair does not preclude the ability to perform a conventional rig repair in the future.
The VOC Voyage: An Enigmatic Journey
Authors: O'Donoghue Mike , Datta Vijay 
Published: May 2013

Abstract
Volatile Organic Compound (VOC) regulations are a primary drive for the research and development efforts of high performance coating manufacturers. Various responses towards VOC stringency and environmental regulations include the introduction of solvent-free coatings, innovative high solids coatings and new generation water borne high performance coatings.
This paper investigates why these low VOC coatings represent important developments for the coatings industry at large and what associated productivity and cost factors are faced by owners using them.
The chemistry of the different coatings and the critical challenges associated with the new technology will be discussed in detail. For instance, a critically important challenge faced by all parties using high performance low VOC coatings is to gain an even better understanding of the pivotal role of surface preparation. Solvent-free coatings, and those containing exempt solvents do not provide the same wetting characteristics as traditional solvent-borne coatings. As a result, an even deeper profile is required for the low VOC coatings, and this is especially true for their use as linings in immersion service.
For optimal results it has been determined that specialized equipment is needed by applicators to transfer many of the high viscosity low VOC coatings and this challenge will also be discussed.
The practical significance of these low VOC coatings is that applicators not only need better equipment but more effective training to successfully apply these coatings to meet the expectations of the end users and ensuring the best net return their investment.
Subsea mining field development concept using a subsea crushing and feeding unit.
Authors: Benbia Ali , Ngim Bertrand , Espinasse Philippe , Parenteau Thomas 
Published: May 2013

Abstract
Seafloor deposits are a very promising source of mineral ore for the near future, discovered over the last 40 years. In particular, Seafloor Massive Sulphides (SMS) are very high grade hydrothermal mineral deposits distributed on the mid ocean ridges, arc and back arc basins in the deep confines of the world oceans. The Technip Subsea Mining R&D program is now entering its 6th year with a clear goal of developping the necessary technologies to recover these sea deposits in an economical, safe, and environementally friendly way.
The current paper describes the current field development that Technip is focussing on. This concept is based on the use of flexible riser anchored to the sea bed and positionned into a wavy shape in order to allow production in rough seas. This concept also focuses on the use of a grabber able to cut and collect the SMS chemineys from top to bottom. The innovative aspect of this concept is to maintain the pumping system on the topside vessel for efficiency and maintenance purposes. One the key unit to be developped is the Subsea Crushing and Feeding Unit (SCFU) that will allow collecting and crushing the material from the grabber content, as well as feeding the crushed material into the high pressure flow circulating inside the riser and jumper network. On this task, Technip has teamed up with ith MMD sizers, a leading crushing equipment supplier for the Mining Industry, to integrate into a subsea structure a sizer and a feeding unit self regulating the transfer of crushed material into the high pressure flow. This development falls into the continuity of the work performed by Technip, MMD, and Perry Slingsby on hyperbaric crushing as presented in OTC 2011 by Benoit Waquet.
A Robust and Flexible Dry Tree Semisubmersible Drilling and Production Platform
Authors: Noce Roberto , Husem Ida 
Published: May 2013

Abstract
When developing new floater concepts for dry tree field developments, some of the main challenges that marine engineers and naval architects face include generating hull designs with motions and global performance that maximize weight efficiencies while minimizing hull offsets, containing the range of top-tensioned riser (TTR) stroke, and providing acceptable steel catenary risers (SCRs) and mooring fatigue life. This paper presents the Octabuoy® Classic (Octabuoy), a robust and flexible deep-draft floater designed specifically for dry wellheads and SCRs. The Octabuoy is the first dry tree semisubmersible platform to be sold and built. Challenges to effective hull design have been addressed by an innovative design in the shape of the columns and proper hydrodynamic design of the hull, which make it a robust platform with virtually no payload or water depth limitations. Extensive numerical analyses and model testing indicate that the Octabuoy's deep draft and overall hull geometry are instrumental in eliminating first and second order motions. The associated minimal motion characteristics and the design of the Octabuoy allow for flexibility in the selection of riser configurations (traditional top-tensioned production risers or SCRs); a variety of installation options (quayside, offshore heavy lift, float over); use in both benign and harsh environments; storage in the hull, and relocation of the platform from a depleted field to another field.
Design Challenges of the World
Authors: Thronson Lowell Carter 
Published: May 2013

Abstract
The Chinese National Offshore Oil Corporation (CNOOC) and Husky Energy Inc. (Husky) have developed Phase I of the Liwan 3-1 Deepwater Gas Field in the South China Sea in which natural gas and condensate flow onshore to the CNOOC Zhuhai Gaolan Terminal via a 30-inch subsea, two-phase pipeline. Forecasts of the gas and condensate flow performed by multi-phase simulation tools predict steady-state liquid slugs arriving at the terminal during normal operations as well as extreme liquid slugs during pigging operations. This is largely due to a combination of the forecasted condensate production and the pipeline's final onshore elevation 190 meters (623 ft.) higher than the offshore elevation. These factors, as well as minor changes in elevation along the pipeline's route, will cause large volumes of liquids to build up in the pipeline. As these liquids move onshore through the pipeline, " slugs" are created. To receive large amounts of liquid in short periods of time, a 7,000 cubic meter (44,000 barrel) capacity was specified.
Although not uncommon to have large, multi-pipe slug catchers at onshore receiving stations, the sheer volume of the predicted slugs during pipeline pigging presented unique challenges to the design and construction of this slug catcher, which is currently deemed to be the largest in the world. A total of 28 finger sections (storage tubes) of 56 inches in outside diameter (OD) each with a length of over 175 meters (575 ft.) were required to store the large volume of arriving condensate. The 28 parallel fingers, coupled with their 175 meter length, required a plot area of over 15,000 square meters (161,400 sq ft.), equivalent to several soccer fields, making this slug catcher the largest single piece of equipment on the entire project.
Since all of the gas and condensate feeding the onshore development and gas processing plant must first pass through the slug catcher without interruption, the criticality of design with regard to flow assurance was paramount to the overall project. The engineering and design of the process and separation capacity in the header systems also had to consider elevated future flow rates and pigging operations. The engineering design was subsequently verified through the use of Computational Fluid Dynamics (CFD).
Several other issues were targeted for special design consideration including large thermal expansions, earthquake loading, slug forces, modularization, construction tolerances and flow assurance.
This paper describes the special circumstances leading to various design decisions which were employed to successfully complete the project.
Simplified Approach for Estimating Pressure and Temperature Profiles for Gas Wells: Verification With Literature Case
Authors: Ruysschaert Rodrigo Aguilar , Hamouda Aly Anis 
Published: May 2013

Abstract
Production from deep gas reservoirs is increasing. Most deep gas reservoirs contain sour gas, which restricts the use of pressure and temperature tools at deep reservoir's pressure and temperature. Few programs are available for estimating the pressure and temperature profiles of production wells in such an environment. Moreover, some of the programs use rigorous approach that depends on input data, which in many cases are not available. This has led users to sometimes, use the default input values or apply linear interpolation between downhole and surface data. These actions may give unrealistic pressure and temperature profiles, especially for compressible fluids in general and specifically for gas wells.
This paper develops a simplified approach using production data to construct temperature and pressure profiles. The approach modifies the Cullender and Smith method for calculating a pressure profile, to account for heat transfer during the transport of fluid within production tubing.
In the case of transient conditions, i.e., the startup of a gas well, it is shown that maximum differences between the simplified developed approach (model 2) and the more rigorous one (model 1) that requires more data are about 0.25% and 2% for the final pressure and temperature, respectively.

Introduction
Properties of transported fluids in pipelines or in production systems change with temperature and pressure. Temperature and pressure profiles are important to predict fluid behavior, i.e., phase change and development of new equilibrium among the different phases. Many approaches to temperature prediction are intended for a specific operation. Ramey Jr. (1972) focused on wellbore heat transmission. Chiu et al. (1991) presented a semi-analytical model to account for heat loss in deviated or horizontal wells. Alves et al. (1992) presented an approach for predicting temperature distribution in wellbores and pipelines. Hasan et al. (1994) predicted heat transfer in two-phase flow in wellbore. Romero (2005) presented an approach for discerning the temperature profile in multilateral wells. Moradi et al. (2011) demonstrated the effect of temperature profiles in deep gas wells on the pressure.
This paper conducts a sensitivity study and comparison between two approaches: that of Moradi et al. (2011) for prediction of pressure drop in deep gas wells, and that of Cullender and Smith (1956). To facilitate comparison, the latter approach is modified to account for temperature.
Wellbore Thermal Performance and Its Impact on Flow Assurance Design of a Subsea Production System
Authors: Ponagandla Veerendhar , Liu Leon , Bufton Scott 
Published: May 2013

Abstract
In many flow assurance designs for subsea production systems, a single assumed rock-layer thickness surrounding the subsea wellbore is used to simulate wellbore thermal performance over the well's entire projection life. This assumption may lead to significant errors in flowing wellhead temperature calculations and potential failure of the flow assurance thermal design.
Based on the Ramey wellbore heat transfer model, this paper presents a new generalized equivalent rock-layer thickness (ERT) model with a time-dependent impact zone of the formation rock-layer surrounding the wellbore. The equivalent thickness of the impact zone of the formation depends on the production time for a producer (or the injection time for an injector). It can be determined by the Ramey dimensionless time function. Various drill-stem-test (DST) data, field production data, and OLGA simulation results have verified the validity of the proposed model. The ERT model can be used to determine the wellbore U-value (overall heat transfer coefficient) and thermal performance during early, mid, and late life for flow assurance design.

Introduction
In the early 1960s, Ramey1 published a classic paper on wellbore heat transmission to present a simple analytical equation for wellbore temperatures based on a simplified heat balance for single-phase liquid or gas flow. Ramey also proposed a procedure to estimate the wellbore U-value for heat losses, comprising both the near-wellbore heat resistance and the transient heat resistance in the formation rock, in terms of a dimensionless time function.
Since then numerous efforts have been made to solve the wellbore heat transfer equations related to single-phase flow or multi-phase flow in the wellbore. In 2004, Hagoort2 revisited Ramey's classic method and presented the rigorous solution to the wellbore heat balance equations. Hagoort demonstrated that Ramey's method is an excellent approximation for the calculation of temperatures in injection and production wells (except for an early transient period) and that the estimation of the overall heat transfer coefficient (related to the dimensionless time function) is good for long production or injection times.
Wellbore thermal performance is a key factor to be considered in the flow assurance design of subsea production systems. Using commercial simulators such as OLGA, the equivalent thickness of the formation rock-layer surrounding the wellbore has to be assumed to calculate the U-value of the wellbore in steady state and transient simulations. This assumption may lead to significant errors in flowing wellhead temperature for normal operation, cooldown time for shutdown, and warm-up time for restart if a single rock-layer thickness is used over the entire field life. To avoid these errors and potential failure of the flow assurance thermal design, this paper presents a simple general equivalent rock-layer thickness (ERT) model that can be applied for flow assurance design work.