This paper presents finding of how liquid hydrocarbon carryover from production separators could form solid contaminants that would later become a root cause for an unexpected failure of tri-ethylene glycol gas dehydration unit to deliver dry export gas. This incident will later be followed by an unanticipated capillary aided gas hydrate blockage inside the gas export line during a planned maintenance shut-down. Upon detailed operational review, all section of TEG dehydration tower unit are opened up, and inspected for: (1) presence of any solid contamination and blockages, and (2) to evaluate presence of internal equipment damages inside the dehydration system. Observations are explained with data analysis and field images, while correlating to TEG dehydration unit's operating parameters; pre and post gas hydrate blockage incident. Compositional analysis using GC-FID, XRD and EDS are conducted on samples collected from the unit to understand its nature. Then, using a customized gas hydrate rocking cell apparatus, gas hydrates growths are observed under 8 °C sub-cooling temperature. From vessel inspection, it is found that liquid hydrocarbon carryover results in accumulation of high chain hydrocarbon deposits (C19-C36), and some mineral scales formation inside the unit. These deposits are found to form when liquid carry-over passes through the reboiler unit. This then gradually blocks the TEG distribution spray nozzles and reduces the efficiency of gas dehydration. Later, with only 20.5% of the spray nozzle found to be in working condition, the dP across the distribution bar exceeds its maximum operating limit, later causing it to split open along the weldment area. Hence, this results a total functional failure to deliver dry gas, and formation of gas hydrate blockage later. On the basis of detailed operational review, field testing, compositional analysis and hydrate growth observations, the sequence of events that later caused a catastrophic capillary aided gas hydrate blockage even in the presence of hydrate risk management program is presented in this paper.
This paper reviews present methods and shares best practice in conducting competency assessments, including their verification, for wells personnel involved in safety and environmentally critical operations with a view to improving HSE Performance and Reducing Major Accident Incidents.
The wells personnel included are those identified Oil & Gas UK (OGUK) as the minimum positions involved in safety and environmentally critical operations. This paper includes a review of the OGUK industry Guidelines on competency for wells personnel – Issue 2 (
There is a wide variance on which direct and indirect assessment methods are used for different onshore and offshore positions. The paper draws conclusions on which methods work best for given positions, how assessors are trained to carry out assessments, the validity of using independent assessors and the benefits of standardizing certain elements of assessment.
A conclusion on the role that professional institutions, including the SPE, may play in the overall assessment of competence is examined. The wide variance of verification methods is reported on and recommendations made on their suitability. The potential for standardization of certain elements of the assessment and verification process will lead to savings, improved utilization of personnel and quality of assessments. Ensuring that assessments are of a common and consistent high standard will improve overall Health, Safety and Environmental performance and help reduce major accidents.
In some wells, especially those drilled through fractured formations, the difference between the fracture pressure and the reservoir pressure becomes narrow. In these wells, maintaining ECD within the limits of fracture and reservoir pressures is a very challenging task, as many parameters have to be adjusted simultanusly to maintain the ECD. When changing the pump rate and the backpressure to maintain the ECD within the MPD window, drilling fluid mass will change and an extra amount of fluid will be accumulated or released from the system as a result of the transient flow. A numerical model is developed to enable the computation of the system mass change at any time due to change of the drilling parameters, which has to match the difference between the inflow and outflow. Any deviation will be interpreted as an external mass source (formation influx) or leak (fluid losses) and this can be used to enables early detection of losses or of formation influxes.
This paper presents a new way to calculate flow pressure for tight oil well with partial penetration fracture and uses dimensionless transformation, Laplace transformation, Fourier cosine transformation and other mathematical methods to solve the diffusivity equation and the solution obtained is simple and accurate. The pressure dynamic flow curve can be divided into four stage. The advantage of the solution is that it can compute efficiently and reduce the amount of computation. The method can be used to determine the optimal degree of opening shot, vertical permeability and other useful parameters.
Venturi tubes are one of the most common types of device used worldwide for wet-gas flow measurement as they are a simple, robust and cost-effective flow meter. They also form the main component in the majority of commercial wet-gas and multiphase flow meters. Major operators acknowledge that more accurate measurement of wet-gas and multiphase flows can be used to optimise reservoir conditions and increase production by 5%. Hence there is a drive to improve the accuracy and increase the use of this technology. In the southern North Sea in the UK there are over a hundred Venturi tubes installed to measure wet-gas flows from wells to enable effective reservoir monitoring and eliminate the need for tests separators. The number of Venturi tubes installed in this one area is set to increase over the next few years with new field developments planned.
There are standards available for using Venturi tubes in wet-gas conditions; ISO/TR 11583 and ISO/TR 12748. However, these only cover limited conditions. The standards and past research has been directed at topside applications where adequate upstream piping lengths are available to ensure optimum performance and high accuracy. However, for more challenging offshore and subsea environments the piping configurations and pressure constraint to reduce space, cost and weight of equipment have limited the deployment of these meters with the recommended configurations and meant that installed meters have significantly larger errors. The UK Regulator for the oil and gas sector has produced flow measurement guidelines which recommend the use of the equations from ISO/TR 11583 when using Venturi tubes to meters wet-gas flows.
NEL has conducted tests to investigate the effect of upstream installations on a Venturi to mimic offshore and subsea conditions. The results indicated that the required upstream lengths were heavily dependent on the flow conditions: in some cases, the upstream lengths can be significantly reduced and in other cases the measurement errors were up to 9%. This is three times the uncertainty limits in ISO/TR 11583 and obviously a large impact on the reservoir management, allocation, and tax.
Most research has been for horizontal installations; this has limited the use of Venturis in vertical installation, which can reduce the footprint on platforms. Additionally, many of the commercial multiphase meters are installed in a vertical installation, and, using the same hardware but different models, could enable cost-effective wet-gas metering. NEL has collected new data and has been able to review the impact of upstream effects on the vertical installation of Venturis.
The data presented in this paper quantifies the impact of upstream installation effects on Venturis in wet-gas flows and when they are installed in a vertical orientation. It is anticipated that this will lead to new research and form the basis on which the current wet-gas standards/best practice will be updated to cover a wider range of installations for not only offshore and subsea installations but also onshore. This should enable use in more restricted installations with guidance available on the impact. This will be a leap forward in offering low-cost options for flow measurement offshore and subsea to ultimately enable increased production, and reservoir management knowledge, and reducing dispute on allocation.
Human Factor Engineering (HFE) addresses interactions in the work environment between people, a facility and its management. FLNG projects bring new HFE challenges with more equipment items that are often larger and often more sophisticated than previously deployed offshore. Deployment of HFE is most cost efficient when started in the early design stages. Timely application of HFE can bring many benefits such as: Designing to allow operation and maintenance throughout the facility’s life considering every single task requiring handling of mechanical components and verification of the FLNG operation and maintenance teams’ resources. Holistic material handling system design Better construction planning
Designing to allow operation and maintenance throughout the facility’s life considering every single task requiring handling of mechanical components and verification of the FLNG operation and maintenance teams’ resources.
Holistic material handling system design
Better construction planning
This paper will present the findings and lessons learned from engineering and construction of recent offshore LNG facilities by TechnipFMC. The perspective of operation and maintenance teams is considered in the HFE process to ensure that experiences and needs are incorporated in the new design. The findings and lessons learned are summarized under keywords for further discussion and recommendation.
Codes, standards and guidelines that are relevant to HFE and material handling are discussed to establish if there is adequate coverage of the requirements for the design, construction and operation of FLNG. Although the discussions of human factors are based on case studies from offshore facilities such as FLNG and large gas processing platforms, the observations and recommendations could be extended to other types of oil and gas facilities.
Zakwan, M. (Petroliam Nasional Berhad, PETRONAS) | Sahak, M. (Petroliam Nasional Berhad, PETRONAS) | Aris, M. Shiraz (Petroliam Nasional Berhad, PETRONAS) | Ariff, Idzham F. M. (Petroliam Nasional Berhad, PETRONAS) | Saadon, Shazleen (Petroliam Nasional Berhad, PETRONAS) | Muhammad, M. Fadhli (Petroliam Nasional Berhad, PETRONAS) | Radi, N. M. (Petroliam Nasional Berhad, PETRONAS) | Daud, N. M. (Petroliam Nasional Berhad, PETRONAS)
The injection of chemicals in a chemical enhanced oil recovery (CEOR) program is expected to impose technical and economic challenges in produced water management especially for offshore installations. The breakthrough of injection chemicals into the surface facilities process lineup, through the water phase, have been tested to be toxic and the typical overboard discharge option will have to be substituted with a much more complex and expensive reinjection scheme if a solution to treat the discharge water is not found. A study to find a chemical treatment solution capable of degrading the toxic components in CEOR produced water was carried out and upscaled towards a pilot implementation for an offshore Malaysian field. The advanced oxidation process (AOP) technique was evaluated as it showed promising capabilities for the intended application. The governing degradation mechanism in the AOP stems from the release of hydroxyl radicals from hydrogen peroxide (H2O2), with the aid of UV radiation, which oxidizes organic components in the injected chemicals to detoxify the outlet stream of the surface facilities process. The results from the experiments showed promising degradation potential where complete degradation of the toxic chemicals was achieved. Specific degradation rates of the chemicals at fixed rates of UV radiation were obtained in this study and used with the electrical energy per order (EE/O) upscaling correlation to size a treatment system for the intended pilot implementation. Compared to other established chemical degradation applications, the upscaling EEO value of 17.9 kWh/1000 USgal/order can be considered to be within reasonable range.
Li, Feng (Southwest Petroleum University) | Li, Xiaoping (Southwest Petroleum University) | Zou, Xinbo (CNOOC China Ltd.) | Duan, Zheng (CNOOC China Ltd.) | Liao, Tian (BHGE) | Lu, Xiaonan (BHGE) | Ren, Yang (CNOOC China Ltd.)
The operator of an offshore oilfield located in South China Sea, has been researching for efficient methods to tackle the production constraints from the increasing produced water amount and maximize oil recovery. An ESP assisted downhole oil and water separation system, known as SubSep system, was designed and successfully installed in year 2014. During the operations, the system achieved designed separation performance but went offline due to heavy sand problem. This paper concentrates on sharing the experience of complete cycle of system design, deployment, operation and post-job investigations, and discussing the lessons learned and future improvements for downhole oil and water separation technology.
The downhole oil and water separation system features in two independent ESP to operate simultaneously: the lower ESP feeds well fluid into multistage hydrocyclone where oil is separated from water, and enters upper ESP to lift to ground, while water is injected to injection layer. Installed in year 2014, the system is the first successful deployment of downhole oil and water separation technology in South China Sea area. The system has totally operated 480 days, during which various operation methodologies were experimented and outcomes analyzed. In normal operation the separated water collected from sample line in water injection zone showed 99ppm oil, and 75% of water was reduced to ground, which signaled the significant success in water and oil separation. The system went offline when surface water rate increased abnormally and injected water with high oil concentration. Further investigation of pulled system showed clear evidence of abrasions from sand and quarts. Future improvement pathways were identified as applying multiple sand control methods, simplifying completion strings, enhancing chemical injection programs and implementing surface experiments.
This paper shares the experience of a complete cycle of design, deployment, operation, and post-job investigations of a downhole oil and water separation system, and provide reference for future improvements and optimizations
Gupta, Pawan (Gas Hydrate and Flow Assurance Laboratory, Petroleum Engineering Program, Department of Ocean Engineering, Indian Institute of Technology Madras) | Sangwai, Jitendra S. (Gas Hydrate and Flow Assurance Laboratory, Petroleum Engineering Program, Department of Ocean Engineering, Indian Institute of Technology Madras)
Methane is the smallest and cleanest burning fuel. It is found in the form of natural gas in which methane present in bulk but contains many impurities such as CO2, H2S which must be removed before being used by the consumer. In addition, it must be stored efficiently and transported economically. Gas hydrate is proposed to be one of the methods for storage, transportation and separation. A subclass of hydrate known as semiclathrate hydrate is capable of acting as a sieve for different sized gas molecules and have the capability to cohost smaller guest gases of specific size. Theses semiclathrate hydrate can be very useful for gas storage and multicomponent gas separation. In this work, a family of quaternary-ammonium salts such as tetra n-methyl/n-ethyl ammonium bromide (TMAB/TEAB) from the clan of tetra-alkyl ammonium bromide are examined at concentrations of 5wt% and 10 wt% for their phase stability along with the TBAB. Additionally, non-isothermal kinetics have been studied. Various experimental data have been obtained at different initial pressures of 8 MPa, 7.5 MPa, and 5.5 MPa to find out the influence of alkyl chain length on methane hydrate formation. It can be observed from experiential results that both TMAB and TEAB have shown thermodynamic inhibition as compared to TBAB. It can also be concluded from the phase stability curves that TBAB has more potential to aid in methane storage and separation than TMAB and TEAB at moderate pressure and temperature. An effect of carbon alkyl chain length is clearly seen on methane gas consumption. It has been witnessed that gas storage in hydrate increases with increase in the alkyl chain length of the salts. From this study, TBAB has found to be a more promising agent for gas processing and methane storage in the form of gas hydrate.
McLean, D. L. (The University of Western Australia) | Macreadie, P. (Deakin University) | White, D. J. (The University of Southampton and The University of Western Australia) | Thomson, P. G. (The University of Western Australia) | Fowler, A. (New South Wales Department of Primary Industries) | Gates, A. R. (National Oceanography Centre) | Benfield, M. (Louisiana State University) | Horton, T. (National Oceanography Centre) | Skropeta, D. (University of Wollongong, NSW) | Bond, T. (The University of Western Australia) | Booth, D. J. (University of Technology) | Techera, E. (The University of Western Australia) | Pattiaratchi, C. (The University of Western Australia) | Collin, S. P. (The University of Western Australia) | Jones, D. O. B. (National Oceanography Centre) | Smith, L. (Woodside Energy Ltd) | Partridge, J. C. (The University of Western Australia)
This paper describes the potential global scientific value of video and other data collected by Remotely Operated Vehicles (ROVs). ROVs are used worldwide, primarily by the offshore oil and gas industry, to monitor the integrity of subsea infrastructure and, in doing so, collect terabytes of video and
This new collaboration prompted a team of international engineers and marine scientists to gather together with West Australian based members of the oil and gas sector and ROV operators, to examine the global scientific value of ROV-collected data. If made available for research, these data have immense value for science to quantify the marine ecology and assist good stewardship of this environment by industry. It was found that most ROV operations are conducted by industry in a way that fulfils immediate industry requirements but which can confound scientific interpretation of the data. For example, there is variation in video resolution, ROV speed, distance above substrate and time (e.g. both seasonal and time of day), and these variations can limit the quantitative conclusions that can be drawn about marine ecology. We examined potential cost-effective, simple enhancements to standard ROV hardware and operational procedures that will increase the value of future industrial ROV operational data, without disrupting the primary focus of these operations.
The ecological value of existing ROV data represents an immense and under-utilized resource with worldwide coverage. We describe how ROVs can unravel the mysteries of our oceans, yield scientific discoveries, and provide examples of how these data can allow quantification of the ecological value of subsea infrastructure. By using these data, we can greatly improve our knowledge of marine biodiversity on and around offshore infrastructure and their environmental impact on marine ecosystems, both of which are particularly important in the consideration and selection of decommissioning strategies. Predicting the environmental consequences of removing or retaining subsea structures after decommissioning relies on an understanding of the ecological communities that have developed in association with these structures during their operational lives. Making industrial ROV data available for scientific research, and collating it in the future using modified protocols, would provide a very positive contribution to both science and industry, allowing the environmental impacts of subsea infrastructure to be quantified. It will also allow industry to contribute to a broader scientific understanding of our oceans, given the location of ROVs in areas that can rarely be accessed by independent researchers. This would provide novel and valuable information about under-researched and little known regions of the world's oceans.