Abstract Pigs are widely used in pipelines and help with meeting operation goals such as keeping the continuous operation and providing the desired throughput and other applications including inspection, cleaning, and also pipeline filling and dewatering. The present study examines leakage and mixing of oil and water during dewatering operations for oil transmission pipelines. When the pig passes through bends and fittings, the sealing between the pipe and the pig becomes less effective and leakage occurs from oil which is pushing the PIG into the water and from water into the production. Therefore, the leaking fluids across the pig cause significant amounts of oil mixing with water ahead of the pig causing environmental issues and a significant amount of waste product downstream (in front) of the moving PIG. On the other hand, water droplets behind the pig can settle causing droplet deposition and corrosion risk. This study aims at modeling the leaked fluids across a pig and the dispersion of the multiphase flow using Computational Fluid Dynamics (CFD). Dynamic models are employed to examine the development of oil-water dispersion. Different scenarios such as the motion of the PIG in a straight pipe with 1-inch (25.4 mm) ID or its passage over a Tee junction is investigated. Through CFD simulations, multiphase flow characteristics such as the water distribution around the pig are examined. Afterward, based on the water concentration, the phase-wetting condition would be identified which assists in pipeline corrosion risk assessment.

Abstract Gas pipelines want to provide transportation flexibility to meet demand, but are always focused on operational safety, reliability, system integrity, and environmental issues. Transportation networks need to ensure the components of gas are acceptable for delivery to end users. Local distribution companies want to meet customer demand and have no existing capacity to remove or extract hydrocarbons from their system. This paper introduces a method for calculating hydrate formation and the phase transfer between gas and liquid to allow the user to know how much liquid exists in a pipeline and the appropriate pigging scenario for the liquid fallout. The paper focuses on determining pigging and how the gas transfers to liquid and the amount of liquid hold up that occurs in the pipeline. Using these mathematical models and algorithms can allow an operator to know the correct timing for pipeline inspection and where in the pipeline system liquid is building up for potential safety monitoring. Introduction and Background Cleaning a pipeline during operation is a maintenance procedure that needs to be done on a regular predetermined frequency using pigs adequately designed for the proper cleaning application. The pigging operation will almost always increase the flow efficiency and reduce operating expenses. In pipelines that have low flow conditions it is more prevalent to see an increase in the collection of free water in the bottom of the pipeline, even in crude oil lines. In low flow conditions you need a mechanical means (pigs) to remove both the solids and liquids that collect in the bottom of the pipeline to help prevent the process of internal corrosion. When a pipeline goes online 100% efficiency cannot be expected, but a routine pigging can keep a pipeline operating at 90 – 95 percent capacity. A pigging requires manual labor and adds cost to the pipeline. An algorithm is needed to estimate the amount of liquid in a pipeline at any given moment and allow the user to know that it is time to pig the pipeline to help alleviate the issues of free water or condensate that is staying in the pipeline. Previous papers have already gone over how the simulation flow and gas condensation work in a gas pipeline. Below is the mathematical procedure to estimate the liquid hold up along with the amount of piggable liquid that is in the pipeline to give a better time to pig a pipeline.

ABSTRACT This paper provides an overview of Pacific Gas and Electric Company's (PG&E) In-Line Inspection (ILI) process from start to finish. PG&E's integrity management program encounters numerous operational challenges as it expands its in-line inspection program to include more challenging pipelines than previously inspected. The company has addressed these challenges by developing a rigorous hydraulic feasibility study process that evaluates risks associated with a respective ILI run before making the decision to proceed with pipeline retrofits to accommodate in-line inspection tools. Several new operating methods have been developed to increase the number of pipelines hydraulically capable of in-line inspections, while reducing risk. Two tools that PG&E has developed to analyze ILI system operations will be discussed. PG&E's Batch Analysis Tool (BAT) is used to conduct complex, multiple-scenario hydraulic analysis. Data results are then processed through an ILI BAT Results Tool, which summarizes BAT data into easily-viewed charts and tables. This allows engineers to consistently analyze and document predicted ILI run gas velocities and system response to varying operations during the inspection. Once detailed analysis is conducted, preparation for the ILI is required. This paper will discuss upgrading pipelines to accommodate inspection tools, developing detailed operating plans, directing real-time operations, and preparing to respond to operational impacts due to anomalies identified on the line. A case study of an ILI on Distribution Feeder Main (DFM) 0617-06 is presented to exemplify PG&E's ILI process from start to finish.

ABSTRACT For long distance single-phase export pipelines, the normal wax control strategy is by sending regular cleaning pigs. The cleaning pigs will mechanically scrape off wax, or any other solid deposited on the pipeline wall, and remove water. This is to assure that there are no obstacles to flow and no corrosion. A key question for single-phase pipeline systems is: What is the minimum cleaning frequency required? This question can only be answered by an evaluation of the following issues where one parameter can alone be governing for the pigging frequency: Equipment design (spares, valves, etc.) Pig design Single phase wax deposition predictions Wax remediation (chemical, pigging, etc.) Wax handling at receiving facilities Evaluation of corrosion control strategy Monitoring possibilities This paper discusses the changes for operations with introduction of a light oil to an offshore heavy oil pipeline. The key success parameter to improve and optimize the existing wax control strategy has been to better utilize operational data together with update of simulations, fluid data and pig design. The result illustrates the importance of continuous monitoring and evaluation of consequences of changed operating conditions for safe and cost-effective operations. In addition to wax control, this paper also discusses changes to flow regime where a low-pressure drop has been experienced compared to design. INTRODUCTION AND BACKGROUND The pipeline system is shown in Figure 1. The existing pipeline system (pipeline 2) is transporting stabilized oil with a gravity of 19°API to onshore receiving facility. In 2015 a new field was tied in to the existing pipeline system with a wye and a new pipeline of 43 km (26.7 miles).

ABSTRACT: The purpose of this work is to present a simplified explicit model to assist the gas controllers during pig run operations. The model considers the mass balance to obtain an approximation of the transient flow profile and calculates the gas velocity using analytical equations to estimate pressure and temperature profiles, while the gas density is calculated by an explicit equation of state for real gas. The effect of seven different models for natural gas compressibility factor are verified on the Pig tracking model. Additionally, the influence of the temperature profile on the pig velocity is analyzed by varying of heat transfer coefficient. A total of five real test cases of pig run in two different section of the pipeline are used to test the model. The results revealed that the heat transfer coefficient slightly impacts the pig velocity. A maximum of 5.8% difference in the average pig velocity is found among the natural gas compressibility equations. As a general observation, the model was able to predict pig position within 8% of error. INTRODUCTION It is well established the importance and benefits of pigging during the many phases of a pipeline life, from commissioning to operation and this includes cleaning, inspection and data acquisition as pointed out by McDonnell et al. (2004). Routinely, as required by the maintenance and integrity programs, is necessary to promote a Pig run to remove lubricants carried out from compression stations or dust and many other times to find corrosion points, dents or cracks. However, a significant amount of time is spent by operational staff during pigging operations. In remote control stations, operators must have adequate monitoring information about pig location to take the necessary actions in order to have safe and reliable pipeline operation.

ABSTRACT: Very low flow rates pose a challenge to gas pipeline pigging due to lack of pushing force for pig movement. However, if a supply source with a high enough pressure is available, a process called "Dynamic Pushing" may be used to create sufficient velocities for the pigging operation. This paper explains the concept, demonstrates how to simulate the process using a transient hydraulic computer model and finally presents a real case of pigging a six mile 36" gas pipeline using this concept with the guidance of the computer model. DYNAMIC PUSHING - THE CONCEPT A normal pigging operation in a gas pipeline relies on the gas flow in the pipe to provide the pressure differential ("pushing") needed to move the pig. There is usually a required minimum speed for the "smart pig" (a computerized mapping tool) to work properly. Sometimes, due to various reasons the maximum flow rate through a pipeline is so low that it is impossible to run a "smart pig" through the line at the speed necessary to obtain valid data. In this case, if a sufficiently large source of high pressure gas is available, a "Dynamic Pushing" process may be used to create a higher flow rate to make the pigging possible. The basic concept is: first, lower the pressure in the pipeline segment to be pigged as far as possible to create a low linepack zone; second, launch the pig into this pipeline segment and apply higher pressure behind the pig to move it at a desired speed. With limited demand flow at the downstream end of the segment, moving of the pig will result in the pressure ahead of the pig to continue to increase. Overall the process will raise the pressure of the pipeline being pigged to rebuild the linepack which was purposely lowered at the first step. This concept is demonstrated in Figures 1 and 2. COMPUTER SIMULATION The Dynamic Pushing process can be simulated using transient hydraulic computer software. In our case, commercially available simulation software has been used for this task. At the first glance the problem appears to be complex in that it involves a moving boundary of pressure across the pig. However if we assume this pressure differential across the pig is small (say, a few psig) and the pipeline is of a relatively large size (36" for example) and short (a few miles only) we can treat the average pressure of the pipeline through the entire length as a single variable, and build the model using the configuration shown in Figure 3. For steady state (initial state of the transient model) the outlet node is set to Known Flow with a flow value assigned. We are now ready to "launch the pig" and start the transient simulation. The minute-by-minute simulation results are presented in the following figures for pigging 6.2 miles of 36" pipeline starting at 255 psig. Figure 5 shows the simulated average pressure change with time.

ABSTRACT Being a planning centre for any activities involving suppliers and customers, PETRONAS Gas Control Center (PGCC) involves in challenging tasks of coordinating various type of operation and maintenance activities like offshore, compressor and plant shutdown, curtailment planning and customers' low demand planning during holiday period. Planning simply based on operators' experience and rule of thumb will give room for errors and inconsistent results. Hydraulic simulation was given a bigger role since 2006 in shutdown coordination and maintenance planning. Various scenarios for various types of activities were simulated and the results were presented in operational and planners meeting. Important decisions were made based on simulation trending. This paper will highlight some of the most important activities that were planned based on the hydraulic simulation, the comparison between simulated and actual profile and the challenges that still lie ahead. ABOUT PETRONAS GAS BHD (PGB) PETRONAS Gas was incorporated in Malaysia on 23 May 1983 under the Companies Act, 1965, as a private limited company and commenced business on 1 April 1984. It was initially a wholly own subsidiary of PETRONAS and known as PETRONAS Gas Sdn Bhd. The Company was converted into a public limited company and changed its name to PETRONAS Gas Bhd (PGB) on 28 March 1995. PGB was formed to serve as the platform to implement the Peninsular Gas Utilisation (PGU) project. The principal activities of the Company consist of the processing of natural gas produced from the gas fields offshore the East Coast of Peninsular Malaysia and the transmission of the processed gas to end-users throughout Peninsular Malaysia and to Singapore. Apart from the PGU system in Peninsular Malaysia, PGB also owns and operates two gas distribution systems in East Malaysia. In this regard, PGB operates as a throughput service company providing the service of processing and transmission of gas to the various customers on behalf of PETRONAS for a fee as set out in a the Gas Processing and Transmission Agreement(GPTA). In expanding the business, PGB had also diversified into Centralised Utility Facilities (CUF) business that involves marketing, manufacturing and supplying of industrial utility products such as electricity, steam, industrial gases and also waste water treatment services to manufacturing plants in the Integrated Petrochemical Complexes in Terengganu and Pahang. The commercial operations of CUF commenced in January 2000. With regards to its CUF business, PGB operates as a commercial provider of industrial utilities products and services to its own customers, with whom it has concluded individual Sale and Purchase Agreements. The various processed products are transmitted via pipelines to PETRONAS customers in the power, industrial and commercial sectors. Processed gas is also supplied to Senoko and Keppel Energy in Singapore through the PGU network.

ABSTRACT This paper addresses the performance of in-depth flow assurance analyses to resolve an ongoing fluids gathering and handling concern at the Glady and Artemas compressor stations located in Glady, West Virginia, and Artemas, Pennsylvania. Efforts included complete analysis of two separate flow line systems, from the gas storage reservoirs to the compressor stations. Steady-state and transient behavior of the production systems were modeled, and hydraulic behavior of the systems over expected operating conditions was analyzed. The study also included a thorough analysis of the compressor station equipment to determine process equipment capacities during heavy draw-down times. Fluid flow from the gas storage fields to the compressor stations was analyzed to identify liquid holdup volumes and locations as well as liquid slugging flowing conditions. Liquid accumulation rates and liquid carryover volumes into the compressor stations were also determined. Pigging operations were also modified based on the results of the analysis. STATEMENT OF PROBLEM Columbia Gas Transmission encountered liquid accumulation and liquid carryover from storage wells into the company's Glady and Artemas compressor stations, located in Glady, West Virginia, and Artemas, Pennsylvania, respectively. During unpredictable times during the storage withdrawal season, large volumes of fluids were carried through a series of gas conditioning devices leading into the dehydration contactor. These fluids contaminated the glycol and were carried into the dehydration reboiler and flared out. This condition created a safety hazard for the personnel at the station and violated the site-specific Title V air permit for the station. The liquids problem occurring at the plant stemmed from changes in operating conditions at the wells and at the pipeline outlet. Each well was assumed to produce water at a rate of 24 gals/mmscf for the Glady field and between 0.67 - 2.7 gals/mmscf for the Artemas field. The amount of liquid in the system and the sizes of the liquid slugs exiting the system were affected by many factors, including individual well gas production rates, operating pressures and temperatures, and pipeline sizes and profiles. As a result, a series of sensitivity cases was evaluated to determine the following in the Glady/Artemas pipelines: Total accumulated liquid volumes in the pipeline segments (in BBLS) Rate of liquid accumulation (in gals/hr) Ascertaining the total liquid volumes in the pipelines helped to determine the maximum amount of liquid that could accumulate in the system if pigging of the pipelines ceased. The volumes were identified in accordance with the assumption that the system would be allowed to flow for long periods of time (five to six months) without pigging and at constant flow rates. Although the volumes generated from these cases will likely never be seen at the Glady/Artemas facilities, they provided an insight into the potential liquid volumes that could exist in the pipelines. Rates of liquid accumulation were determined at various flow rates for an average arrival pressure at the Glady/Artemas facility. These cases helped identify the amount of liquid that could build up in the pipeline over time.