bluuebunny/crossref_metadata_2025_split huggingface dataset:
Implementing a Deepwater-Pipeline-Management System
Authors: Samosir Theo , Popineau Dominique , Lechon Alain 
Published: March 2015

Summary
As an operator, Total has experienced significant deepwater maintenance andrepair activities, including cut-out and replacement of a damaged section ofwater-injection line, replacement of a flexible riser, replacement of an anchorline and its pile, and repair of an umbilical termination head (UTH).
There are few deepwater-pipeline operators with experience in pipelinerepairs that need to be carried out with significant preparation time forintervention tools, including engineering and testing of the tools. Deepwateroperations [including inspection, maintenance, and repair (IMR)] require acompletely different paradigm than conventional offshore operations, with needfor specialized competencies, contractors, and tools. The pipeline-repairactivities mastered in conventional offshore operations are becoming difficulttasks in deep water because they have to be performed remotely and the pipelinecharacteristics are quite different. Furthermore, there are many importantchallenges that still need to be overcome, such as repair of pipe-in-pipesystems, repair of production bundle, repair of flowline with hydrogen sulfidecontent, and repair of flowline connection, all of which challenge research anddevelopment to find proper tools and methodologies for deepwaterintervention.
This paper describes the strategy developed and implemented ondeepwater-pipeline intervention, based on a deepwater operational experiencebuilt over a decade. It also presents experiences of dealing with integrityissues and how to move forward in existing operations while preparing forfuture developments. Once the proper technologies are acquired, apipeline-repair system should be established as part of anoperational-management philosophy.
From the design stage, an operator involved in the development of deepwateroperations should give serious consideration to how condition monitoring of thepipeline and its appurtenances will be performed and to how pipeline sectionswill be repaired or replaced should there be any failure during production.Being well prepared to face unexpected failures in the deepwater-pipelinenetwork would allow the operator to maintain the level of integrity of thedeepwater-pipeline network, minimize production loss and shortfall, minimizeintervention costs, and maintain the operator's image with international mediaand the national oil company.
Risk-Based Passive Fire-Protection Optimization
Authors: Munoz-Garcia Enrique 
Published: March 2015

Summary
Passive fire protection (PFP) has been used in the oil and gas industry for many years as a method to avoid/delay global collapse of offshore installations. However, location of PFP has normally been based on simplistic assumptions, standards, guidance, and methods that do not always consider the real response of the structure to fire. The resulting PFP schemes can be conservative, leading to unnecessary cost to the operator in terms of application and maintenance costs. More importantly, there is the potential for the PFP scheme to be insufficient for the actual fire hazards, which will increase the level of risk to the personnel onboard. Fire-induced progressive collapse is a function of the level of redundancy of a structure; it is for this reason that redundancy analyses have sometimes been used as a simplistic method to calculate the level of PFP required. However, this method does not take into account the size of the fire threat against which the PFP is designed and could lead to less-than-conservative results because it considers removing only one member of the structure at a time, without considering reduction in the strength of the surrounding members as they are also being heated by the fire. Performance-based fire-collapse analysis provides an understanding of the response of the individual members, as well as the entire structural system, to fire. Understanding the failure mechanisms, susceptibility to progressive collapse of the structure, and key members that must remain in place during an accident situation allows for the optimisation of the PFP scheme, protecting only the required members while allowing for local failure of redundant members. The present paper provides a comparison between the different methods, and provides case studies that have resulted in optimum PFP schemes linked to design fires on the basis of acceptable risk levels.
Optimization of Integrated Template Structures for Arctic Subsea-Production Systems
Authors: Pribytkov Evgeny A. , Zolotukhin Anatoly B. , Gudmestad Ove T. 
Published: March 2015

Summary
This paper analyzes the various selection methods of integrated template structures (ITSs) for use in the Arctic environment. First, an analysis of several actual projects is carried out, with the specific features of each described thoroughly. An important part of the work is devoted to the requirements of ITSs conceived in relevant NORSOK (Norsk Sokkels Konkuranseposisjon), International Organization for Standardization (ISO), and DNV (Det Norske Veritas) standards. The main elements of subsea production modules are examined in this work, along with their specific characteristics and components. Operation and installation of subsea modules in the Barents Sea are also analyzed in this paper. Four scenarios, with differing numbers of ITSs (two, three, four, and six) and differing quantities of well slots in each, are considered. For each scenario, a study of related marine operations (required for installation) is performed, and a program for installation-cost estimates is developed, resulting in the determination of an optimal design for the ITSs. Various parameters affecting the cost of subsea infrastructure are analyzed and studied from different perspectives (e.g., geometrical well-pattern systems, distance between drilling slots, drilling and construction costs). Risk analyses of the threats and consequences involved in the process are performed, and risk-assessment matrices and mitigation actions are established. As a result, a model for selecting an optimal ITS for the Arctic/Sub-Arctic region is created.
Hybrid Approach by Use of Linear Analogs for Gas-Network Simulation With Multiple Components
Authors: Leong Chew Y. , Ayala H. Luis F. 
Published: March 2015

Summary
The generalized Newton-Raphson method is routinely deployed in industrial and academic applications in order to solve complex systems of highly nonlinear equations. Prime candidates for this solution methodology are complex natural-gas transportation networks, of which the nonlinear governing equations can be written in terms of nodal, loop, or nodal/loop formulations to solve for all network pressures and flows. A well-known issue of the Newton-Raphson iterative methodology is its hapless divergence characteristics when poorly initialized or when flow loops are poorly defined in loop or nodal/loop formulations. In this study, a method of linear analogs is discussed, which eliminates the need for user-prescribed flow or pressure initializations or loop definitions in the solution of the highly nonlinear gas-network governing equations. A comprehensive solution strategy based on analog transformations is presented for the analysis of a gas-pipeline network system comprised of not only pipes, but also common nonpipe network elements such as compressors and pressure-dependent gas supplies (e.g., wellheads). The proposed approach retains advantages of Newton-nodal formulations, while removing the need for initial guesses, Jacobian formulations, and calculation of derivatives. Case studies are presented to showcase the straightforward and reliable nature of the methodology when applied to the solution of a steady-state gas-network system analysis with pipeline, compressor and well-head components.
Design Method Combining API and ASME Codes for Subsea Equipment for HP/HT Conditions Up to 25,000-psi Pressure and 400°F Temperature
Authors: Pathak Parth D. , Kocurek Christopher G. , Taylor Samuel L. 
Published: March 2015

Summary
A current challenge in the offshore industry is the design of subsea equipment for pressures exceeding 15,000 psi and temperatures exceeding 250°F. This combination of pressure and temperature has been fairly accepted as the start of the high-pressure/high-temperature (HP/HT) region. The current American Petroleum Institute (API) standard for designing subsea equipment, API Specification (SPEC) 17D (2011), is limited to a working pressure of 15,000 psi and provides little guidance on temperature conditions exceeding 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 HP/HT conditions greater than 15,000 psi and 250°F. This paper shows the evaluation of a combined load-capacity chart for an API SPEC 17D flange flow-loop [API SPEC 6A (2010), 4 in., 20 ksi) for a design pressure of 20,000 psi and a 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 both to 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 on 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 Technical Report (TR) 6AF1 (1998) charts. This work has been performed to demonstrate both the acceptance of existing methods for HP/HT conditions and to introduce the advanced ASME design methods for designing API SPEC 17D subsea equipment. The methods presented are acceptable for designing equipment up to working pressures of up to 25,000 psi and temperatures up to 400°F.
Mechanical Vapor Recompression for the Treatment of Shale-Gas Flowback Water
Authors: Hayes Thomas D. , Halldorson Brent , Horner Patrick H. , Ewing John Jay R. , Werline James R. , Severin Blaine F. 
Published: March 2015

Summary
Used extensively by the food, chemical, and pharmaceutical industries, the mechanical-vapor-recompression (MVR) process is viewed as a reliable method for recovering demineralized water from concentrated brines. Devon Energy has supported the operation of an advanced MVR system at a north-central Texas (Barnett shale region) treatment facility. At this facility, pretreatment included caustic addition and clarification for total-suspended-solids and iron control. Pretreated shale-gas flowback water was then sent to three MVR units, each rated at 2,000–2500 B/D (318–398 m3/d). Data were collected during a 60-day period in the summer of 2010. Distilled-water recovery volume averaged 72.5% of the influent water to the MVR units. The influent total dissolved solids (TDS) fed to the MVR units averaged just under 50 000 mg/L. More than 99% of the TDS were captured in the concentrate stream. The fate of multivalent cations; total petroleum hydrocarbons (TPH); and benzene, toluene, ethylbenzene and xylenes (BTEX) throughout the treatment system was determined. Most of the iron and TPH removal (90 and 84%, respectively) occurred during pretreatment. The total removal of iron, magnesium, calcium, barium, and boron from the distillate exceeded 99%. BTEX removal from the distillate exceeded 95%. Electric power at the facility was provided by two natural-gas generators, and compressors associated with the MVR units were driven by natural-gas-fueled internal-combustion engines. Energy requirements at the entire treatment facility were tracked daily by total natural-gas use. Best-fit correlations between treated water and distillate production vs. total plant use of natural gas indicated that there was a base power load throughout the facility of approximately 120 to 140 Mscf/D (3400 to 3960 m3/d) of gas. Approximately 48 scf natural gas/bbl influent water treated (270 m3/m3 influent) or 60.5 scf/bbl distillate produced (340 m3/m3 distillate) was required; this represents an energy cost of less than USD 0.25/bbl treated (USD 0.04/m3 treated) and approximately USD 0.30/bbl of distillate product generated (USD 0.048/m3 distillate), assuming a natural-gas cost of USD 5/million Btu (USD 4.72/GJ). Performance in terms of water recovery and product-water quality was stable throughout the 60-day test.
Evaluating Wellbore Accessibility and Productive Performance for a Long-Reach Multilateral Tight Gas Well in Changbei Block
Authors: Li Li , Zhi Guo Hong , Millan Hilarion , Qiang Zhang , Tao Zhang , Lei Cui , Sheng Li Yin 
Published: March 2015

Abstract
Changbei gas field is on the north edge of the Mauwusu desert in the Ordos basin in north-central China. The game-changing dual-lateral well concept is used in this tight gas reservoir. The typical well completion is kicked off at about 1700 m, and the hole is built to an inclination of 85° at the top of the reservoir with the 12¼-in. section. The first leg of the 8½-in. reservoir section is drilled for 2000 m. The second leg is drilled with an openhole sidetrack from leg 1. More openhole sidetracks are drilled from legs 1 and 2 if unstable intervals are penetrated. Upon reaching total depth (TD), a 7-in. slotted liner is run to protect any unstable claystone intervals.
As part of the well and reservoir surveillance activities and with the aim of improved understanding of the reservoir and well behavior, production logging is required to obtain the gas-contribution profile along the horizontal wellbore; the profile is used to confirm the size of the sand bar, facies distribution, wellbore condition, and production contribution from each leg. Previous attempts with wheel-driven tractors and conventional production logging tools (PLTs) were unsuccessful because most of the PLT runs encountered bad downhole conditions, such as water/mudcake, which led to failure of the tractors and PLT centralizers. The mudcake and debris could not be cleaned from wellbores, even though the wells had been produced at high rate.
To collect needed data, an advanced PLT consisting of an array of minispinners and optical and electrical holdup sensors was conveyed by an electrically powered tractor operating on the inchworm principle to successfully log a long-reach multilateral well. A workflow was followed to obtain wellbore accessibility and perform flow profile evaluation for the complex downhole conditions at Changbei. This was the first time a flow profile was obtained in Changbei block.
Achieving Economically Successful Deployment of Coiled Tubing at Sea as Downline to Repair a Gas Pipeline
Authors: Machado Frederico , Souza Raphael , Fonseca Roberto 
Published: March 2015

Abstract
Offshore pipeline pre-commissioning activities normally involve the use of downline to permit the communication between surface equipment (normally rigged up in a vessel or rig) and the subsea pipeline injection/vent point. Recently, a major operator in Brazil deployed a 1 3/4-in. coiled tubing (CT) string as downline at sea using a methodology to maintain a smooth bend radius to help reduce fatigue issues during operations. Using CT as downline for this operation saved the operator USD millions by eliminating the need to replace a pipeline section.
The 40-kilometer (km) pipeline had a blockage composed of pigs, debris, and hydrates. After two failed interventions, the operator decided to install a subsea hot tap on each side of the plug, displace the hydrocarbon, and clean the pipeline to cut the section and replace it with new pipe. The blockage was located 6 km from the center of the pipeline. CT string was deployed to the seabed (1400 m) and was attached using soft sling in a deployed 8-ton clump weight positioned next to the pipeline. A 25-m flying lead hose was used in the bottomhole assembly (BHA) to connect the CT to the pipeline subsea hot tap near the plugged section and compensate vessel movement. After attaching the CT string on the clump weight, the vessel was moved away from this point to deploy 40 m of the CT on the seabed, forming a smooth bend radius. A Nitrogen generator unit (NGU) was used to displace gas in the pipeline to the production unit flare. Cleaning operations were completed using a pig propelled with filtered seawater provided by pumping equipment located on the production unit. The execution plan required that all fluids be recovered onboard the support vessel through the CT attached to the subsea hot tap.
Using CT and established best practices, the team was not only able to clean the pipeline section as planned but also eliminate the need to cut and replace the pipeline section. The CT string was kept under water for more than 170 hours, demonstrating its capability to satisfactorily function as downline equipment during this operation.
Residual Curvature and Moments in CT due to Bending
Authors: Newman Kenneth R. 
Published: March 2015

Abstract
When CT with internal pressure is bent around the reel or guide arch, and straightened in the injector chains, it experiences both plastic and elastic deformation. This results in internal residual stresses which cause bending moments and residual curvature. A “straightener” can be used to reverse bend the CT, which causes it to be fairly straight (no significant residual bend) but it still has significant residual stresses. Residual curvature and stresses decrease the buckling load (the CT is more prone to buckling) and cause safety issues if the CT is suddenly released. They can affect the fatigue life, but they are not in themselves an indicator of the amount of fatigue damage (as some have mistakenly thought). This paper presents the concepts and equations used to determine the residual curvature and residual stresses for a sequence of bending events, axial loadings, with internal pressure. These concepts and equations are then used to demonstrate the behavior of CT for several practical situations such as when it is run in and out of a well, and when it passes through a straightener.
Advancement in Mechanical Manipulation Enables Pulling Forces of 60,000 lbs on E-line – Operational Experiences from Pulling Stuck Plugs and Tools
Authors: Buch Jørgen , Mourani Houssam , Ngo Dong 
Published: March 2015

Abstract

Objectives/Scope:
Accidental plug setting and stuck tools is a cause of great frustration, operational delays and ultimately deferred production. A cost-efficient and swift resolution is always desired. This paper presents a new development in engineering in the form of a hydraulic stroking tool with the ability to apply 60,000 lbs of force. The tool has already been applied in the North Sea; lessons learned from these recent operations are disclosed in this paper.

Methods, Procedures, Process:
In one operation, a plug was accidentally set across the Christmas-Tree (XMT) and blowout preventer (BOP), effectively eliminating the XMT as a well barrier element and constituting a serious HSE risk. Conventional solutions failed to release the plug due to an insufficient pull force and then a failing jar.
In another well, the setting tool had malfunctioned, resulting in a partially set plug and a stuck tool. Repeated attempts with heavy duty fishing equipment had damaged the fishing neck, further complicating the fishing operation as the seting tool had failed before it could break the stud connecting to the plug.

Results, Observations, Conclusions:
The high performance of the recently developed stroking tool turned out to be the solution to save both of these demanding operations. In the first well, it was estimated that the force required to shear the plug from the setting tool would be 43,300 lbs. The operation was completed in three runs with no misruns, which saved the operator from prolonged exposure to HSE risk, including well control situation.
In the second well, the force required to shear the stud and free the setting tool was 40,000 lbs. Two release devices were combined in the toolstring, one below the hydraulic stroker and one below the cable head in order to allow further contingencies to mitigate risk and increase safety. After four attempts, the shear stud parted, thus completing the setting sequence and freeing the stuck setting tool. The operator got the well back on track, saved five days of rig time and avoided the costs of a workover rig.

Novel/Additive Information:
The case stories in this paper constitute the first jobs performed with the new tool. Two important features discussed are reduced HSE risks and increased operational efficiency.
Combined Electric Line Milling and Clean-out to Eliminate Fluid Costs for Multi-Stage Frac Preparation in Southeast Saskatchewan
Authors: MacLeod Anthony , Ray Jeremy , Bittner Scott 
Published: March 2015

Abstract

Objectives/Scope
Clients utilizing Coiled Tubing (CT) for straddle frac operations in multi-stage horizontal wells often encounter cement stringers preventing the frac bottomhole assembly (BHA) from reaching plug back total depth (PBTD) and the packer from sealing to the casing wall. This paper presents the learnings from a &gt;90 well campaign of preparing for fracking operations using an electric line (e-line) milling and clean-out tool. The wells were mostly cemented, 4.5″ liners with frac sleeves. This technique reduced frac preparation costs in the cemented wells by approximately 30%.

Methods, Procedures, Process
The common practice in Southeast Saskatchewan (SE Sask) is to perform a “well prep” operation prior to the frac equipment's arrival to the well site. A CT unit equipped with a rotating scraper/mill—and associated fluids—is used for the clean-out, adding to the logistical coordination and well costs. Fluid has several costs associated with it: the cost of the fluid/water itself, heating for winter operations, trucking and disposal. However, “well prep” is considered “cheap insurance” by most operators working in SE Sask compared to the potential costs of a waiting frac crew.

Results, Observations, Conclusions
An operator in SE Sask has had success with an alternative clean-out solution to replace the use of fluid for well preps by introducing an e-line method consisting of an electric milling & clean-out tool with a casing collar locator (CCL). The mill is conveyed by e-line tractor and is equipped with a scraper mill to confirm the PBTD and ensure that there is no cement debris or sheath present that could negatively affect the frac operation. Various bailers can be added to collect the cement debris in the same run and ensure it is removed from the wellbore.
In combination with the clean-out service, a CCL is deployed and logged to surface to pinpoint the exact sleeve location to be referenced during the frac operation. This new, efficient clean-out solution has proved slightly more time-consuming (~3-5 hours) but yielded significant cost savings of approximately 30% per well of prep costs. These savings come from using e-line equipment, eliminating fluid costs and offering inherently safer operations with a low carbon footprint.

Novel/Additive Information
Moreover, the paper will discuss the future applicability of this ‘additional application’ for pre-logging runs as a means to reduce total completion costs in cemented wells. This is achieved by using the e-line milling tool as a pre-run for casing inspections or cement evaluation logging.