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Qin, Hao (Colorado School of Mines) | Qu, Anqi (Colorado School of Mines) | Wang, Yan (Colorado School of Mines) | Zerpa, Luis (Colorado School of Mines) | Koh, Carolyn (Colorado School of Mines) | Bodnar, Scot (Multi-Chem Halliburton) | Daly, Sean (Multi-Chem Halliburton) | Palermo, Thierry (Total) | Mateen, Khalid (Total)
The formation of gas hydrates is considered a major flow assurance issue resulting from high pressure and low temperature conditions during petroleum production in deep water developments (
Traditionally, thermodynamic approaches are used to prevent the formation of hydrates in flowlines, including the injection of thermodynamic hydrate inhibitors (THIs), such as methanol or glycols. THIs work by shifting the hydrate phase equilibrium conditions to a lower temperature and higher pressure, which makes the condition unfavorable for hydrates to form (
Santos, Hugo F. L. (Petrobras) | Perondi, Eduardo A. (UFRGS) | Wentz, André V. (Senai-RS) | Silva Júnior, Anselmo L. (Senai-SC) | Barone, Dante A. C. (UFRGS) | Galassi, Maurício (Petrobras) | Castro, Bruno B. de (Petrobras) | Reis, Ney R. S. dos (Petrobras) | Basso, Eduardo D. (UFRGS) | Pinto, Hardy L. da C. P. (Petrobras) | Ferreira, André M. G. (Petrobras) | Ferreira, Lincoln H. T. (Petrobras)
Methane hydrates and paraffin plugs on flexible lines are concerns in offshore production. They may stop wells for months, causing high financial losses. Sometimes, operators use depressurization techniques for hydrate removal. Another strategy is using coiled tubing or a similar unit to perform local heating or solvent injection. However, frequently these strategies are not successful. In those cases, a rig may perform the operation, or the line may be lost.
We developed a robotic system to perform controlled local heating and remove obstructions. The system developed can access the line from the production platform. It uses a self-locking system to exert high traction forces. An umbilical with neutral buoyancy and low friction coefficient allows significant friction reduction. It allows moving upward and in pipes with a large number of curves. Coiled tubing and similar units cannot do that. Carbon fiber vessels and compact circuits give the flexibility to move inside 4-in. flexible pipes.
In addition, a novel theoretical model allows the cable traction calculation using an evolution of the Euler-Eytelwein equation. Experimental tests validated this model using curved pipes, both empty and filled with fluid, and using different loads. Experimental tests also confirmed the external layer traction resistance. Furthermore, the carbon fiber vessels were pressure tested, indicating a collapse resistance of 57 MPa (8,300 psi). Besides, exhaustive tests of the onboard electronics and the surface control system guarantee the communication reliability.
In addition, a theoretical model allowed the design of the 25 kN (5.6 kip) traction system considering the self-locking system, the contact with the wall, and a diameter range. Four prototypes allowed us to compare hydraulic and electric drive systems, validate the self-locking mechanism up to its limit, analyze the hydraulic system for leg opening and translation, and prove the traction capacity. Finally, a theoretical model allowed the local heating system and the temperature to increase. The experimental validation of the system on a cooled environment demonstrated its ability to increase temperature. Further, it allowed the obstruction removal in a controlled manner, avoiding damage to the polymeric layer of the flexible line.
Fu, Weiqi (China University of Petroleum (East China)) | Wang, Zhiyuan (China University of Petroleum (East China)) | Chen, Litao (China University of Petroleum (East China)) | Sun, Baojiang (China University of Petroleum (East China))
Summary In the development of deepwater crude oil, gas, and gas hydrates, hydrate formation during drilling operations becomes a crucial problem for flow assurance and wellbore pressure management. To study the characteristics of methane hydrate formation in the drilling fluid, the experiments of the methane hydrate formation in water with carboxmethylcellulose (CMC) additive are performed in a horizontal flow loop under flow velocity from 1.32 to 1.60 m/s and CMC concentration from 0.2 to 0.5 wt%. The flow pattern is observed as bubbly flow in experiments. The experiments indicate that the increase of CMC concentration impedes the hydrate formation while the increase of liquid velocity enhances formation rates. In the stirred reactor, the hydrate formation rate generally decreases as the subcooling condition decreases. However, in this work, with the subcooling condition continuously decreasing, hydrate formation rate follows a "U" shaped trend--initially decreasing, then leveling out and finally increasing. It is because the hydrate formation rate in this work is influenced by multiple factors, such as hydrate shell formation, fracturing, sloughing, and bubble breaking up, which has more complicated mass transfer procedure than that in the stirred reactor. A semiempirical model that is based on the mass transfer mechanism is developed for current experimental conditions, and can be used to predict the formation rates of gas hydrates in the non-Newtonian fluid by replacing corresponding correlations. The rheological experiments are performed to obtain the rheological model of the CMC aqueous solution for the proposed model. The overall hydrate formation coefficient in the proposed model is correlated with experimental data. The hydrate formation model is verified and the predicted quantity of gas hydrates has a discrepancy less than 10%. Introduction Natural gas hydrates are solid inclusion compounds that are formed when the local pressure-temperature field can meet the requirements of hydrate nucleation (Sloan and Koh 2008; Koh et al. 2011).
One of the biggest challenges after the initial gas field discovery lies in the transportation. The natural gas supply is constructed in such a way that transportation remains an integral part of the gas utilization system. This is because the operator has to understand the mechanism behind transporting from the well to the wellhead; from the wellhead to the topside while efficiently avoiding hydrate formation; from the topside to the processing facilities and from the processing facilities to the delivery point for the final consumers.
This paper was structured to address subsea gas pipeline flow assurance issues relating to the initiation of hydrate and internal corrosion. Through experience and extensive literature studies, an Optimization Systematic Model was developed. This model is procedural in nature, incorporating both risk analysis and predictive models. The model was further used to investigate the susceptibility of the case study, Inter-western African Gas Pan Pipeline (IAGPP), to hydrate and internal corrosion. The results of the case study confirmed that the model is helpful in that it can bring flow assurance issues to management focus. This research suggested a new derived equation – the Thermo-Mechanistic Model (T-MM), used to explain PIPESIM simulation results and the optimization options. The T-MM can be used to understand the behavior of gas enthalpy to variations in gas pipeline flowrate. In general, there is a need to keep gas pipeline capacity optimization in focus; to proactively avert cases of hydrate and internal corrosion by using the model developed. Learning from the IAGPP case study also shows that there is the need to accurately assess gas availability for transmission.
Ahmad, Sheraz (China University of Petroleum (Beijing)) | Li, Yiming (China University of Petroleum (Beijing)) | Li, Xiangfang (China University of Petroleum (Beijing)) | Xia, Wei (China National Oil and Gas Exploration and Development Company) | Chen, Zeen (China University of Petroleum (Beijing)) | Wang, Peng (China University of Petroleum (Beijing))
In the current study, a novel methodology is introduced based on classical conservation model equations of mass, momentum and heat transfer in porous media sediments. Set of model equations have been used in discrete form to investigate liquefied high pressure CO2 transformation into solid hydrates. During this numerical analysis, CO2 phase transition, effect of hydrate nucleation on temperature variations by exothermic heat release and effect of injected CO2 pressure and temperature on hydrate growth speed have been studied.
The results of numerical simulation show that at 0.01 Darcy intrinsic permeability of formation, a significant pressure delay is witnessed during CO2injection in hydrate formation. At 18 MPa injection pressure, the pressure hardly becomes stable during 4 weeks of hydrate growth process. Due to slow pressure distribution, it also affects temperature distribution and hydrate covered length during hydrate growth process. Low formation absolute permeability decreases the speed of injected CO2 and it is also unable to reduce the temperature of formation. Thus, the temperature near the injection point continuously increases at initial stage of hydrate growth process(during 1stweek) and finally, exceeds the formation initial local temperature. From 2nd week, the exothermic effect diminishes and temperature starts decreasing near the wellbore region but in the far zones it exceeds from initial temperature and temperature boundary moves towards extended formation. The partially saturated hydrate covered length during this time is 585 m with 315 m fully saturated hydrate region length. When the injection pressure is increased to 19 MPa, both regions extend to 617 m and 325 m respectively. The 5 K decrease in injected CO2 temperature doesn’t give any appreciable results. But if dual-injection method is used, the hydrate storage capacity can be enhanced significantly using less injection pressure.
ABSTRACT: Rock mechanical analysis of gas hydrate dissociation has been a challenge since discovery of subsea hydrate formations. This paper provides a platform to couple Finite Difference and Finite Element Methods to achieve rock mechanical itemization for hydrate bearing sediments. The data from the models are incorporated in a code developed on “Matlab”. The code is capable of coupling the data from both models and plot them against time and space parameters. The output of this cod explains the hydrate dissociation behavior in the rock formation and enable to select the required mud weight profile suitable to drill the wellbore. The results suggest that at the time of hydrate dissociation the pore pressure of hydrate bearing sediment is depleted by 12%. Further, in order to drill through hydrate bearing sediments a narrow mud weight window is required ranging from 10 to 11 MPa. A unique behavior of near wellbore pore pressure gradient is also investigated which reveals the fluctuation of pore pressure near wellbore as stress fields near the wellbore are confined during drilling procedure. Thus, this study provides a complete package of rock mechanics for hydrate bearing sediments.
Natural gas hydrates has become the center of focus because it has been publicized that 1 CF of gas hydrate could hold as much as 170 ft3 (Dalmazzone etal, 2003) of gas which means natural gas trapped in permafrost and offshore hydrates can bring level of self-sufficiency to countries that relay on imported oil and gas (Mingjun Yang Et al, 2016). Conspicuously, natural gas hydrates are present in both marine and permafrost environment (Robin Susilo Et al 2007). Natural gas hydrates attracted the attention primarily for their existence in far greater amount as compared to conventional or unconventional sources, secondly, for there diversified geographical distribution across the globe. Still dealing with natural gas hydrates is complex because accurate phase equilibria prediction is very important, especially when it comes to hydrate stability (M. Naveed Khan et al, 2016). All the techniques to evaluate hydrate behavior are incorporated with certain risk due to environmental instability of hydrates at room temperature (Na Wei, 2016). Natural gas hydrates has a common existence deed that is they are stable at low temperature and high pressure (Tingting Luo et al, 2016). Furthermore, the sedimentary strength of marine strata is also dependent on hydrate stability. Therefore, the overall stability of subsea hydrate bearing sedimentary rock layer is reliant on shear strength characteristic of layer. In contrast, these shear strength characteristics of layer are dependent on rate of heat energy transfer, technically known as thermal flux or thermal regime (Philip Long Et al, 2010). The thermal regime is basically the reason for melting of water and emission of gas and dissociation. Hence, it can be said that the thermal flux is the actual factor that is reason for seabed instability because due to disturbance in thermal flux the pore space hydrate saturation modifies and also it effects the grain structure of rock layer. Henceforth, the important phenomenon to understand is that hydrate dissociation in any case takes place due to rise in temperature. This thoughtful phenomenon is basically dependent on the combination of pressure and temperature condition desired for stable gas hydrate existence (S. Dangayach et al, 2015). Simply, the concept of hydrate dissociation can be explained with better illustration by understanding the temperature-pressure regime. Therefore, this study presents a novel concept of percolation mechanics in hydrate bearing sediments. Figure 1 shows the Physical Structure of Hydrate Sample during Thermal Regime Investigation in which it can be clearly observed that when hydrates are frozen there is not particle movement however as temperature rises the particles moves down and water traces can be seen definitely.
Qin, Hao (Center for Hydrate Research, Colorado School of Mines) | Srivastava, Vishal (Center for Hydrate Research, Colorado School of Mines) | Wang, Hua (Dept. of Computer Science, Colorado School of Mines) | Zerpa, Luis E. (Center for Hydrate Research, Colorado School of Mines) | Koh, Carolyn A. (Center for Hydrate Research, Colorado School of Mines)
Recently the concept of "no external gas hydrate control measures" has been proposed, whereby gas hydrate formation can occur in oil and gas subsea pipelines during steady state and transient operations, with the operational window defined by predictive analytic tools. Flow assurance engineers routinely use computer programs, including transient multiphase flow simulators coupled to a gas hydrate kinetics model to simulate gas hydrate formation and transportability. Given the complexity in multiphase flow modeling, modern machine learning technologies, especially artificial intelligence, could be applied to solve high-level, non-linear problems, such as evaluating gas hydrate risk based on measurable process parameters.
In this work, several machine learning techniques, such as regression, classification, feature learning with an algorithm/framework like support vector machine (SVM) and neural networks (NN), are applied to analyze the data sets on: 1) hydrate tests conducted at pilot-scale flowloop facilities (4,500 data points), as well as 2) transient operation field data. The classification/regression model based on flowloop test data uses several independent input variables (features), such as water cut, gas-oil ratio, hydrate particle cohesive force, fluid velocity, oil viscosity, specific gravity, interfacial tension, and time in the hydrate stable zone, to output the hydrate fraction and probability of hydrate plugging in the pipeline. The semi-supervised learning model was applied based on the field data use as input, including water cut, shut-down time (where applicable), and gas-oil ratio to determine the level of hydrate resistance to flow during restart or dead oil displacement after production shut-down.
The flowloop based machine learning model exhibited good prediction accuracies in test and validation processes, and was used to assess the hydrate risks in an actual field. The field data based machine learning model demonstrated the ability to construct field risk maps.
The machine learning technique could be potentially applied in hydrate management to evaluate hydrate risks in subsea oil/gas pipelines. As a complement to more complex transient multiphase flow simulations, this machine learning approach can aid in the development of advanced hydrate management strategies.
Sum, Amadeu K. (Colorado School of Mines) | Zhang, Xianwei (Colorado School of Mines) | Sa, Jeong-Hoon (Colorado School of Mines) | Lee, Bo Ram (Colorado School of Mines) | Austvik, Torstein (Equinor ASA) | Li, Xiaoyun (Equinor ASA) | M. Askvik, Kjell (Equinor ASA)
Deadlegs are defined as pipe sections in intermittent use for production or special services in oil/gas production systems. Deadlegs often pose hydrate control challenges to gas and oil production systems as the fluid inside is close to stagnant and therefore can be rapidly cooled by the environment without proper insulation or heat tracing. Water vapor can condense in the deadleg, resulting in a potential hydrate risk. Over time the deadleg may be blocked completely by hydrates. The hydrate challenges, if not properly managed, can cause severe consequences in terms of safety and cost for oil/gas productions. A systematic study has been performed to better understand the process and mechanism of hydrate deposition in deadlegs. To study hydrate deposition in deadlegs experimentally, laboratory scale deadleg systems were designed and built to consider pipe sizes of 1-, 2-, 3-, and 4-in. inner diameter and approximately 50 in. long. The pipes were gas-filled and saturated with water from a reservoir at the bottom of the pipe. The experimental work focused on measuring hydrate deposition, and in some cases, plugging, for different water reservoir temperatures (30 to 80 °C), pipe wall temperatures (-10 to 15 °C), and duration (1 to 84 days). The results from measurements provided insights into the dynamic process of hydrate deposition, such as the mechanism for hydrate deposition, plugging, and distribution along the pipe.
In this paper, we present for the first time, a classification system for naturally-occurring gas hydrate deposits existing in the permafrost and marine environment. This classification is relatively simple but highlights the salient features of a gas hydrate deposit which are important for their exploration and production such as location, porosity system, gas origin and migration path. We then show how this classification can be used to describe eight well-studied gas hydrate deposits in permafrost and marine environment. Potential implications of this classification are also discussed.
Urunwo, Elechi Virtue (World Bank Africa Centre of Excellence for Oil Field Chemical Research, University of PortHarcourt.) | Ikiensikimama, S. S. (University of Port Harcourt) | Ajienka, J. A. (University of Port Harcourt) | Akaranta, O. (University of Port Harcourt) | Onyekonwu, M. O. (University of Port Harcourt) | Odutola, T. O. (University of Port Harcourt) | Okon, E. O. (University of Port Harcourt)
Gas hydrates pose a very serious flow assurance problem by impeding flow especially in the offshore environment where accessibility is restricted. This paper takes a look at gas hydrate inhibition in a simulated offshore environment using plant extract (PE) as local inhibitor. The essence of this work is to source for an effective and bio-degradable gas hydrate inhibitor from locally sourced materials and also ascertain their effectiveness as compared to a conventional hydrate inhibitor Mono ethylene glycol (MEG). Experiments were conducted using a mini flow loop. It will involve mitigating hydrate formation using varying weight percentages of the inhibitor (1wt%, 2wt% and 3wt %) and then evaluate their effect on hydrate inhibition in the mini flow loop. Sensitivity charts of pressure, temperature, time for both the local inhibitor and MEG were made. From the analysis, 1 and 2 weight percentages of the local plant extract (PE) showed better inhibitory capacity than MEG while 3 weight percentages of plant extract (PE) and MEG had a close match. Based on the result gotten, the PE could be recommended for field trial.