This paper covers the problem related to AC interferences on East West Gas Pipeline (EWPL) and the mitigation measures taken for reducing / eliminating the same. AC interference was observed in Hyderabad region due to AC EHV Transmission lines crossing EWPL, three phase transformers and Single wire earth return (SWER) single phase transformers in the vicinity of pipeline. AC PSP voltage up to 80 Volts were observed on pipeline during night hours for which various mitigation measures were taken to bring down in acceptable range. Similarly, there is possibility of high voltage surge at station facilities along the pipeline route due to vicinity of multiple structures, long pipeline length and having multiple conducting structures at MLV stations comprising of RTD's, die-electric isolators, impulse Tubing for power gas and associated power gas and control equipment. Surge travel to such system can result in equipment failures. Various proactive measures to mitigate such instances were adopted on pipeline system and are implemented successfully. This paper illustrates the extent of the risk of corrosion, surge impact due to AC interference / surge and gives insight to various methods deployed for minimizing these risks in simple and most economical way. It also highlights the need for collaboration and operational coordination between the pipeline operators and state electricity boards to resolve such issues mutually & in most effective manner.
Gupta, M K (Oil and Natural Gas Corporation Ltd.) | Sukanandan, J N (Oil and Natural Gas Corporation Ltd.) | Singh, V K (Oil and Natural Gas Corporation Ltd.) | Bansal, R (Oil and Natural Gas Corporation Ltd.) | Pawar, A S (Oil and Natural Gas Corporation Ltd.) | Deuri, Budhin (Oil and Natural Gas Corporation Ltd.)
This paper discusses a case study of one of the onshore field of ONGC where while processing well fluid, frequent surge has been observed leading to shutdown of the SDVs creating severe operational problems and loss of production. It was imperative to find out the problematic wells/lines located in clusters which contribute for surge formation and mitigation approach with minimum modifications.
A transient complex network of sixty five wells flowing with a different lift mode such as intermittent gas lift, continuous gas lift etc were developed in a dynamic multiphase flow simulator OLGA. Time cycle of each well were introduced for intermittent lift wells. Simulation study reveals pulsating transient trends of liquid flow, pressure which was matched with the real time data of the plant and hence confirms the accuracy of the model. After verifying the results, different scenarios were created to determine the causes of surge formation. After finding the cause, a low cost approach was considered for surge mitigations.
An integrated rigorous simulation was carried out in OLGA, by feeding more than 12,000 data points to obtain model match. Several scenarios were also created such as optimization of lift gas quantity, optimization of elevation and size. Trend obtained after each scenario was pulsating behaviour and it matched with the real time data appearing in the SCADA system of the field. After rigorous simulation with each scenario, it was established that the cause of surge forming wells/pipelines. Once the root cause of surge has been confirmed then quantum of liquid generated due to surge was determined. Adequacy checks of the existing separators were carried out to estimate the handling capacity of the existing separators at prevalent operating condition. After adequacy check it was found that existing separators cannot handle the surge generated in that time interval leading to cross the high-high safety level, resulting closure of shut down valve (SDV). After establishment of root cause of the surge, a low cost solution with small modification in pipelines and control system/valves was adopted to arrest the surges. It was first of its kind simulation carried out for a huge network of wells/ pipelines by feeding more than 12,000 data to analyze the surge formation cause and capture its dynamism owing to wide array of suspected causes. This will help to address the challenges of efficiently reviewing the entire pipeline network while designing new well pad/GGS and will also help to arrest surge by adopting a low cost solution wherever such situation arises.
As the oil and gas industry is moving towards digital oil field, the selection of leak detection system (LDS) has become more crucial. Early detection of leaks not only saves environment from Hazardous hydrocarbons but considerable loss in production is also saved. This paper discusses about both internal and external LDS and its applicability for onshore and offshore fields. This paper will ease the selection process of LDS for green and brown fields of both offshore and onshore installation.
In line Inspection (ILI) Interval are often based on conditions that are assumed constant over long sections of pipeline - perhaps entire pipeline systems. Many pipeline operators are following the fixed ILI Interval based on statuary requirement irrespective of different local corrosion growth conditions prevailing on the particular pipeline system. Scheduling the ILI based on maximum interval defined in statuary requirement may be very unrealistic and pose threats to the integrity of these pipelines. This technical paper discusses the importance of ILI Interval, corrosion growth rate analysis, recent development to determine the ILI Interval, an engineering approach to calculate appropriate ILI-RunInterval, mitigation plan to extend the ILI-RunInterval for particular pipeline system. This technical paper would enhance the awareness among the pipeline operators to appropriately calculate the ILI-Run Interval which would cost beneficial to pipeline operators in long term without any integrity threats.
Wang, Bohong (China University of Petroleum) | Liao, Qi (China University of Petroleum) | Zheng, Jianqin (China University of Petroleum) | Yuan, Meng (China University of Petroleum) | Zhang, Haoran (China University of Petroleum) | Liang, Yongtu (China University of Petroleum)
The site selection of the facilities in oilfields is one of the important issues for surface engineers. In the progressive development of oilfields, new wells are explored and developed, and new process facilities (PFs) should be constructed to gather and process the fluid from these new wells. The emission of the PFs will affect the surrounding environment, including water sources, forests, and human settlements. Thus, the environment should be considered as one of the key aspects in the design process of facilities. Different locations of facilities in the oilfields will affect both the construction cost and environmental cost. Thus, a balance has to be found. In addition, the uncertainty of production rate of well fluid poses a great challenge to this problem. To solve the above problem, this paper provides a systematic methodology.
The objective function consists two parts: construction costs and environmental cost. The solving algorithm has involved three layers of looping programming to calculate the value of objective function. First the weather conditions are generated by the Monte Carlo method, then the second loop is for the study areas, and the third loop is for the new facilities locations. After all the loops of iterations are completed, the objective functions are calculated, and the influence of the environment can be evaluated. Finally, the best solution can be obtained.
The effectiveness of the proposed method is demonstrated through a design problem in an oilfield. The candidate locations for PFs are previously determined, and the optimal construction plan is solved by our method. The quantitative influence on the environment to these candidate locations can be evaluated. After determining the coefficient of the construction cost and the environmental cost, the best locations for the process facilities with the lowest total cost can be determined.
A multi-objective model for the site selection of process facilities in oilfields is proposed, which has not been done by existing literatures. The construction cost and surrounding environment are both considered in the model. This work has the potential to serve as a decision-support tool for surface engineers in oilfields.
Chullabrahm, Pattarapong (PTT Exploration and Production Public Company Ltd) | Saranyasoontorn, Korn (PTT Exploration and Production Public Company Ltd) | Svasti-xuto, Maythus (PTT Exploration and Production Public Company Ltd) | Trithipchatsakul, Chao (PTT Exploration and Production Public Company Ltd) | Sunderland, Damon (Arup Pty Ltd) | Ingvorsen, Peter (Arup Pty Ltd) | Madrigal, Sarah (Arup Pty Ltd) | McAndrew, Russell (Arup Pty Ltd)
This paper presents an integration of geology, geohazards, geophysics and geotechnical assessments for a design of an offshore gas production facility and an associated export pipeline. The gas field described in this paper is located off the North West coast of Australia in the Timor Sea in a water depth of approximately 130m.
Various resource development options were investigated during the Concept Select / pre-Front End Engineering Design (pre-FEED) phase of the project. These options included fixed and floating structures in the infield area and a 300km long export pipeline that ties into an existing gas trunkline connecting to an onshore processing plant.
To provide the necessary engineering due diligence to allow the project to progress further, several phases of geo-related investigations were undertaken to assess various geohazard challenges and foundation risks. Some of these challenges include a pipeline route traversing several steeply sloping seabed canyons, potential activation of turbidite sequences, and the presence of very soft carbonate sediments to calcarenite rock.
This paper describes these ground related challenges and how they were constrained through the geo-related investigations conducted, observations made and results obtained. Ground related challenges are described in two parts: Pre-FEED export pipeline routing reviews focusing on geohazard, geophysical and geotechnical considerations and ‘real time’ pipeline engineering Finite Element Analysis (FEA) performed offshore. Compared to normal practice, this non-standard offshore analysis allowed a preferred pipeline corridor to be identified during the survey with an informed understanding regarding feasibility and likely seabed intervention, thus optimising the field survey time and cost; and Staged acquisition and integration of infield geophysical and geotechnical data for developing high level assessments of foundation concepts.
Pre-FEED export pipeline routing reviews focusing on geohazard, geophysical and geotechnical considerations and ‘real time’ pipeline engineering Finite Element Analysis (FEA) performed offshore. Compared to normal practice, this non-standard offshore analysis allowed a preferred pipeline corridor to be identified during the survey with an informed understanding regarding feasibility and likely seabed intervention, thus optimising the field survey time and cost; and
Staged acquisition and integration of infield geophysical and geotechnical data for developing high level assessments of foundation concepts.
Key benefits of conducting an integrated approach to geo-related challenges on a complex site will also be presented in this paper.
The ‘Pseudo’ Dry Gas (PDG) subsea concept is being developed to dramatically improve the efficiency of subsea gas transportation by removing fluids at the earliest point of accumulation. The technology will increase the geographical reach from receiving gas terminals, allowing asset owners to prolong production life without the need for more expensive design solutions. This paper will provide an overview of the innovative technology, demonstrating that a 200 km plus tie back can be achieved, without compression.
Increasing the distance of subsea tie-backs increases the liquid inventory, with constraints on pipeline diameter for slug free flow. The PDG concept is based on a main gas line integrated with piggable gravity powered drain liquid removal unit and pumps (a smaller fluid line transports separated liquid). Multiple units are specified to drain liquids as they condense in the line, maintaining near dry service. Liquid free operation removes the constraint on pipeline diameter. Specification of a large diameter pipe (within installation limits) reduces backpressure on the wells, enhancing recovery. Minimum stable flow limits are removed, improving tail end recovery.
Current stranded gas development options (subsea compression, floating facilities, FLNG) generate a step change in costs which can make a project uneconomic. This is even more acute in mature and semi-mature basins where existing gas processing facilities / LNG terminals already exist offshore or onshore along with sunk costs from the exploration. A case study for a 185 km pseudo dry gas subsea tie-back to shore demonstrates the PDG concept feasibility. This result is used to argue that the PDG concept should be included in the suite of subsea processing options considered by Operators in early field development planning.
The pipeline inspection is one of the most critical tasks in the oil and gas industries. The operation of a remotely operated vehicle (ROV) for the pipeline inspection is very costly since it requires both a human operator and the support vessel to which an ROV must be tethered. Furthermore, this tether also limits the surveillance ability of an ROV. Thus, the use of autonomous underwater vehicles (AUVs) can greatly reduce the operation cost of pipeline inspection since an AUV can freely and automatically navigate without tethering to support vessel. In order for an AUV to navigate automatically under the limited vision in the underwater environment, the forward-looking sonar (FLS) is the essential part since the quality of images captured by an optical camera degrade significantly by the turbid water and the low-light condition whereas images produced from an acoustic sonar As a result, in this work, we are interested in the use of a 2-D multi-beam Forward-Looking Sonar (FLS) to capture echo images on a frontal vision since acoustic signals can pass through tiny particles in turbid medium water . This deployment ensures that an image of pipelines can be captured regardless of low underwater visibility conditions. Other types of sonars that are regularly used in underwater visual inspection include the side scan sonar (SSS), synthetic aperture sonar (SAS), and multi-beam echo sounder (MBES). There are a limited number of works that focus on the pipeline detection problem. An optical camera was employed in  for visual feedback and heading control, SSS and MBES were used in ,  and  for pipeline tracking, and, in , FLS was used for linear object detection and tracking.
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.
Sun, Hehui (No.1 Mudlogging Company, BHDC, CNPC) | Lao, Liyun (SWEE school, Cranfield University) | Li, Dengyue (No.1 Mudlogging Company, BHDC, CNPC) | Tao, Qinglong (No.1 Mudlogging Company, BHDC, CNPC) | Ma, Hong (No.1 Mudlogging Company, BHDC, CNPC) | Li, Huaiyu (No.1 Mudlogging Company, BHDC, CNPC) | Song, Changhong (No.1 Mudlogging Company, BHDC, CNPC)
More and more early kick/loss detection (EKLD) devices are being used in drilling operations, whether in the field of onshore or offshore drilling. In the field of deepwater and offshore drilling, high-precision electromagnetic flowmeters and Coriolis flowmeters was used to measure the inlet and outlet flow rates of drilling fluids. Good effect was achieved, but are affected by drilling fluids, space limitation of the wellsite and production costs when in the field of shore drilling, engineers usually use the paddle- flowmeter and ultrasonic liquid level meter to measure the inlet and outlet flow. It exists the problem of low measurement accuracy and prolonged warning time. In order to improve the accuracy of measurement and the accuracy of early warning, the electromagnetic flowmeter has been studied in terms of flow measurement at the outlet of on-shore drilling. The study found that the installation position of the electromagnetic flowmeter in the V-shaped test pipeline is a key factor that determines the accuracy of measurements. The influence of different fluid types on the measurement was studied by fluid dynamics. The fluid model was established using Ansys fluent software, and the boundary conditions were set in conjunction with the relevant parameters of the drilling fluid. It was found that the descending segment of the V-shaped pipeline was suitable in the state of laminar and dispersed flow. It is an appropriate mounting position for the electric flow meter; for the slug flow, the rising section is a suitable installation position. The theoretical conclusion is verified by laboratory simulation and field tests. The results of theoretical research were used to optimize the design of the test pipeline, and the problems of transient large flow passage and solid-phase debris deposition in the field were solved, and good results were achieved. An automatic grouting module was developed based on the accurate measured outlet flow data. The automatic grouting operation is very helpful for the construction process of drilling and triping, improved the safety level of well control, and laid a good foundation for the large-scale application of EKLD devices in the field of shore drilling.