The considerations and standards guiding pipeline design insures stability and integrity in the industry. The fluid flow equations and formulas presented thus far enable the engineer to initiate the design of a piping or pipeline system, where the pressure drop available governs the selection of pipe size. This is discussed below in the section on velocity considerations for pipelines. Once the inner diameter (ID) of the piping segment has been determined, the pipe wall thickness must be calculated. If there are no codes or standards that specifically apply to the oil and gas production facilities, the design engineer may select one of the industry codes or standards as the basis of design. The design and operation of gathering, transmission, and distribution pipeline systems are usually governed by codes, standards, and regulations. The design engineer must verify whether the particular country in which the project is located has regulations, codes, and standards that apply to facilities and/or pipelines. In the U.S, piping on offshore facilities is mandated by regulation to be done in accordance with ANSI/ASME Standard B31.3. Some companies use the more stringent ANSI/ASME Standard B31.3 for onshore facilities. In other countries, similar standards apply with minor variations.
Assuming steady-state flow, there are a number of equations, which are based upon the general energy equation, that can be employed to design the piping system. The variables associated with the fluid (i.e., liquid, gas, or multiphase) affect the flow. This leads to the derivation and development of equations that are applicable to a particular fluid. Although piping systems and pipeline design can get complex, the vast majority of the design problems encountered by the engineer can be solved by the standard flow equations. The basic equation developed to represent steady-state fluid flow is the Bernoulli equation which assumes that total mechanical energy is conserved for steady, incompressible, inviscid, isothermal flow with no heat transfer or work done.
A pilot of cryogenic distillation technology is designed and installed for separation of the high CO2 concentration of feed up to 80 mol % from natural gas. However, the main concern was the dry ice formation during depressurization or blowdown might cause the pipeline and equipment blockage and consequently resulting in safety issues.
A dynamics simulation and modeling were conducted using commercialize software to determine the settle out temperature during the blowdown especially emergency condition. The investigations were focused on the high operating pressure and low operating temperature with a high CO2 composition which is closer to transient condition and solid region. Then, more comprehensive modeling was conducted by incorporating the equipment and piping design data including the sizing of relieve valves (RVs) and blowdown valves (BDVs). The accuracy of information is very crucial to obtain more reliable results.
It was observed that at high operating pressure, (50 to 75 barg) and low operating temperature,(-58 to 15 °C) the settle out temperature due Joule-Thomson (JT) effect were −58 °C and −92 °C for 60% and 80% CO2 concentration, respectively. Based on the phase diagram, in this condition, the CO2 will be under a solid region. As a result, the Minimum Design Metal Temperature (MDMT) of −100 °C was selected for equipment and pipelines design to avoid material brittle-fracture. Few mitigations measure were designed and installed to avoid the CO2 solidification. The BDVs were installed at the warmer area to minimize the JT effect leading to lower operating temperature than CO2 solidification temperature resulting to potential equipment blockage. The electrical heat tracings were installed at the outlet flange and outlet line of RVs and BDVs to maintain fluid temperature above CO2 solidification limit. This is to prevent CO2 solid from attaching to the pipe wall and build up in the piping in the event of relief. Another mitigation was by installing the outlet line with sloped toward vent header and free from instrument probe or sensor to prevent CO2 solid from build up at piping dead leg section. As a result, no sign of CO2 solid found in the sections that equipped with mitigations measure during experiments.
An inherently safer design of equipment and pipelines are very crucial especially for high CO2 concentration, high operating pressure and low operating temperature with the appropriate mitigations to avoid catastrophic failure.
The existing API equation for internal leak predicts the internal pressure to overcome the pin-box contact pressure generated from the makeup interference plus the energizing effect of internal pressure which enhances the seal. For threaded connections, internal and external pressures close the connection and increase the leak resistance, whereas axial loads open the connection and decrease the leak resistance. These competing effects must be included to accurately assess the connection leak resistance under any combination of loads at any point in any string. Following the same approach used by API for internal leak, this paper obtains similar results for external leak. For API connections, the effects of combined axial force and backup pressure are then incorporated into the internal/external leak equations using results from the Mitchell and Goodman (2018) paper presented at the 2018 SPE-IADC Drilling Conference. Sensitivities of leak ratings to combined loads for API connections are presented for both tubing and casing sizes. An example design case shows the importance of considering combined loads.
To mitigate the risk of twistoff during high dogleg-severity (DLS) drilling and to reduce cost of service delivery induced by frequent recuts, an advanced rotary shouldered threaded connection design with significantly enhanced fatigue life over existing API connections has recently been developed and released for field operation. Modeling and simulation techniques had been extensively used to drive the design and qualification processes. In this paper, an overview of the numerical modeling methodology and its experimental validation is presented with an emphasis on the key functional requirements of the design.
The newly developed connection design involves an optimized thread form and an advanced manufacturing process. Finite element analysis (FEA) was heavily used to optimize the design prior to physical prototyping and testing. High-fidelity modeling methods were developed, and comprehensive numerical analyses were performed to digitally evaluate the performance of the new design, including fatigue resistance, galling resistance, combined load capacity, sealability, and so on. The FEA models had very well predicted the performance of the new design, which was later validated through full-scale experimental tests. Several qualification tests, such as torsional yield limit test and tensile capacity test, were carried out completely digitally. As a result of the extensive modeling and simulation work conducted, the connection design met all requirements in one iteration.
The work presented in this paper represents a successful example of model-driven product development, which significantly reduces development time and cost. It is the first time that a high-fidelity modeling methodology, in conjunction with full-scale experimental validation, is introduced for advanced rotary shouldered threaded connections in the oil and gas industry.
This updated NACE International standard practice provides the most current technology and industry practices for material requirements and the use of tape coatings for external mainline coating, coating repair, coating rehabilitation, and coating weld joints on buried metal pipelines. The standard is applicable to underground metal pipelines in the oil and gas gathering, distribution, and transmission industries, as well as water and wastewater pipelines. This standard is intended for use by corrosion control personnel, design engineers, project managers, purchasing personnel, and construction engineers and managers.
This NACE International standard practice provides the most current technology and industry practices for material requirements and the use of tape coatings for external mainline coating, coating repair, coating rehabilitation, and coating weld joints on buried metal pipelines. This standard is intended for use by corrosion control personnel, design engineers, project managers, purchasing personnel, and construction engineers and managers. It is applicable to underground metal pipelines in the oil and gas gathering, distribution, and transmission industries, as well as water and wastewater pipelines.
This standard was prepared in 2009 and revised in 2019 by NACE Task Group (TG) 251, “Coatings, Tape for External Repair, Rehabilitations, and Weld Joints on Pipelines.” This TG is administered by Specific Technology Group (STG) 03, “Coatings and Linings, Protective: Immersion and Buried Service.” It is sponsored by STG 04, “Coatings and Linings, Protective: Surface Preparation,” and STG 35, “Pipelines, Tanks, and Well Casings.” This standard is issued by NACE International under the auspices of STG 03.
In today's challenging work and business environment, swift response to structural integrity concerns is the need of the hour to minimize the damages that will reduce down time, specifically in oil & gas sector. The solution devised to address structural concerns shall prevent further failure of structural members and avert major catastrophic accidents, as they support process equipment and piping. This paper outlines case studies of such structural failures, potential reasons of incidents and approaches followed in restoring structural integrity in a safe and economical way that ensures uninterrupted plant operation.
Key parameters to be studied / considered while arriving solutions to structural damage / incidents include reliability of data, primary cause of incident, inventory of readily available material, execution feasibility under plant operating conditions thereby avoiding plant or unit shutdowns and manpower skillsets. Due to various constraints, the solution arrived may be temporary that averts multiple structural failures or a major accident. Further studies would be required to identify the root cause and to confirm or enhance the implemented solution that will reaffirm long term integrity of structure.
In almost all of the incidents, some of the common steps followed for swift restoration of structural integrity include conducting a site survey to identify and judge the probable cause, reviewing available data, structural assessment and details of material in stock.
After analyzing numerous factors, diverse approaches unique to each incident were considered in arriving a solution that is fit-for-purpose.
Structural integrity issues, if not attended swiftly, can worsen the situation leading to safety concerns and major accidents. Solutions adopted for various incidents ensured restoration of structural integrity with minimal consequences. Suggested improvements and recommendations were implemented and no further issues were reported until this time.
The objective is to study and develop the economical clamp to use for leakage repair caused by pipe crack at piping supports in gas regeneration system, which is operated under thermal cyclic condition and not possible to call the ad-hoc plant shutdown window. The process of this study is to analyze the thermal expansion of piping and clamp, which is a cause of the gap at contact surface between 8″ piping and clamp. The clamp design is developed with understanding the influence of heat conduction as well as the material expansion. The experiment has been setup to verify the clamp design in the scope of performance and endurance test. The expected end result is the efficiency of clamp to secure the pressure while gas leakage is occurred under thermal expansion effect. The result from design, development and experiment to prove its performance and endurance is indicated that this ecomomical clamp is in good condition and can secure the pressure under gas leakage situation. This project now generates the benefit to preserve production and sale (prevent unplanned plant shutdown), prompt response (perform as an emergency repair) and very low fabrication cost (able to reduce fabrication cost for 40%, approx.).
Piping systems under multi-phase flow are subjected to unbalanced forces during plant operation and they experience vibration. Usually, the piping vibrations can be minimized by either modifying piping configuration/supports or alteration of operational modes. This paper presents an engineering study of a challenging piping vibration problem, which was resolved by an inventive and cost optimizing solution, as there are limitations in modification of existing pipe support/configuration. The inventive resolution reduced implementation cost to the Company without impacting the operations.
A comprehensive study was conducted to identify the root cause of piping vibration in rich amine piping system (36" pipe) from heat exchanger to amine regenerator, a tall column. The vibration screening and likelihood-of-failure calculations were carried out based on Energy Institute's guidelines and observed that the piping system is in concern/problem zones.
The process study including review of hydraulics, verification of line size and control valve design was performed to identify the root cause of piping vibration. The piping stress analysis (static/dynamic) was carried out with actual operating conditions, which is under multiphase flow with varying density/forces.
The process study revealed that the flow velocity and momentum are within process design requirements. However the flow in the piping system is multi-phase type, which generates unbalanced forces due to slug loads at each elbow of the piping system.
Based on piping stress analysis results, it was identified that the natural frequency of piping systems is variable as the whole weight of the vertical piping system is resting on spring type supports, which in turn, are supported from vertical vessel cleats. These supports are provided to take care of relative displacements between vessel and vertical piping systems. Piping configuration cannot be modified considering large bore piping and requirement of huge structural supports. The existing supports also cannot be modified as they are connected to pressure vessel and will impact its design.
In this scenario of multiple limitations, the indispensable flow induced vibrations of piping can only be minimized by damping the effect of flow-induced excitation with dampers. The dampers have elastic-viscous material in its main restraining body which can absorb the piping vibrations. The damper vendor performed the stress analysis, considering the effect of the damper in the whole piping system, and ensured the integrity of piping system.
The challenge of maintaining existing spring supports and achieving required damping of piping vibration was successfully accomplished. Considering large sized piping and requirement of major structural supports in case of modifications, proposed solutions could be treated as cost effective and innovative. Though it was not possible to eliminate the root cause, this alternate innovative solution helped to not only to minimize vibration, but also optimize implementation/shutdown costs. Vibration damper in piping systems is unique to piping installations.