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Collaborating Authors
Hydrate Management in Restart Operations of a Subsea Jumper
Kumar, Asheesh (Centre for Long Subsea Tiebacks, School of Engineering, Department of Chemical Engineering, University of Western Australia) | Di Lorenzo, Mauricio (CSIRO Energy) | Kozielski, Karen (CSIRO Energy) | Singh, Amrinder (ConocoPhillips Company &, Bartlesville) | May, Eric F. (Fluid Science and Resources Division, School of Engineering, Department of Chemical Engineering, University of Western Australia, 35 Stirling Hwy, Crawley WA 6009, Australia) | Aman, Zachary M. (Centre for Long Subsea Tiebacks, School of Engineering, Department of Chemical Engineering, University of Western Australia)
Abstract Subsea jumpers are tie-in systems with a characteristic M-shaped geometry, employed to connect subsea facilities such as wellhead trees to manifolds. During well restart after a prolonged shut-down, subsea jumpers are exposed to a significant driving force for hydrate formation. Employing the recently-constructed HyJump flowloop, designed to mimic subsea jumpers operating at hydrate forming conditions, an experimental campaign was conducted to assess the influence of pipeline temperature, gas flow rate, liquid inventory, and inhibitor content on hydrate deposition during simulated shut-down and restart operations. In this work, we acquired baseline data on the gas sweep efficiency in HyJump for a wide range of gas restart velocities to characterize hydrodynamic behaviour in the absence of hydrates. Preliminary experiments were also conducted to evaluate the jumper operability in hydrate forming conditions. The HyJump flowloop consists of a test section connected to independent gas and liquid injection equipment at the inlet and gas separation facilities at the outlet which allows a continuous recirculation of gas and a once-through pass of the liquid. The test section has a complex geometry, with three identical low points and two high points with horizontal length of 12′ 10˝ and 7′ 7˝, respectively, and total height is 13′ 2˝. The test section is equipped with 12 pressure and temperature sensors regularly distributed, a MEG sensor in the second low point, a throttling valve downstream of the first high point to mimic the wellhead choke, and a viewing window at the outlet. In gas sweep experiments, each of the three low points was loaded with 1.6 gallons of water and natural gas at 1200 psi. During these tests, the pipeline temperature was maintained above 60 °F where hydrates are not expected to form. The system was maintained for six hours at a pipeline temperature of 41 °F (17 °F sub-cooling) for hydrate formation tests. Gas sweep velocities were varied in a range between 0.06 and 3 ft/s. The results illustrate that a superficial gas velocity of 3 ft/s was required to fully remove liquids from the jumper. However, gas velocities below 0.16 ft/s did not result in any substantive changes to the liquid inventory. Thus, low flow restart conditions could offer a significant driving force for hydrate formation in the jumper at low temperature. The preliminary gas restart tests conducted in hydrate forming conditions provided clear evidence of hydrate deposition at gas velocities below 0.16 ft/s. Hydrate formation in subsea jumper spools is poorly understood and a rare topic of discussion within scientific literature. This unique "HyJump" facility offers new insight to assist operators mitigate the risk of hydrate blockage by manipulating gas restart rates after well shut-down in the absence of (or with severely limited) chemical inhibition.
- North America > United States (0.93)
- Asia (0.68)
A produced-hydrocarbon stream from a wellhead encounters formation of solid gas-hydrate deposits, which plug flowlines and which are one of the most challenging problems in deep subsea facilities. This paper describes a gas-hydrate model for oil-dominated systems, which can be used for the design and optimization of facilities focusing on the prevention, management, and remediation of hydrates in flowlines. Using a typical geometry and fluid properties of an offshore well from the Caratinga field located in the Campos basin in Brazil, the gas-hydrate model is applied to study the hydrate-plugging risk at three different periods of the well life. Additionally, the gas-hydrate model is applied to study the performance of the injection of ethanol as a thermodynamic hydrate inhibitor in steady-state flow and transient shut-in/restart operations. The application of the transient gas-hydrate model proved to be useful in determining the optimal ethanol concentration that minimized the hydrate-plugging risk.
- South America > Brazil > Rio de Janeiro > South Atlantic Ocean > Campos Basin > Area do 4-RJS-495 > Barracuda and Caratinga Field > Caratinga Field (0.99)
- South America > Brazil > Campos Basin (0.99)
Dynamics of Hydrate Behavior in Shut-In and Restart Condition in Two and Three Phase System
Kakitani, Celina (Federal University of Technology of Parana UTFPR) | Marques, Daniela C. (Federal University of Technology of Parana UTFPR) | Neto, Moisés A. Marcelino (Federal University of Technology of Parana UTFPR) | Teixeira, Adriana (Petrobras Research Center CENPES) | Valim, Leandro S. (Petrobras Research Center CENPES) | Morales, Rigoberto E. M. (Federal University of Technology of Parana UTFPR) | Sum, Amadeu K. (Colorado School of Mines)
The exploration fields under more severe conditions is accompanied by concerns about solid precipitation/deposition and hydrate formation. Transient operations, involving shut-in and restart is the most challenging scenario with risk for hydrate problem. The residence time of the production fluids associated to the rate of heat loss to the ambient seabed during the period of shut-in may increase the potential risk of hydrate blockage. This work is focused on understanding the hydrate formation, breakup, agglomeration and deposition, reproducing the shut-in and restart conditions in a lab-scale. Experiments were performed using a high pressure cell coupled to a rheometer using a custom-designed impeller and a rocking cell experiments with visual capabilities. A two-phase (water and gas) and three-phase (water, oil and gas) systems were used in the experiments. Also, the impact of the shear applied at restart on the hydrate morphology was evaluated. The viscoelastic behavior was observed in most shut-in and restart tests. Understanding the mechanism of hydrate formation and agglomeration during transient conditions may help to develop strategies to avoid hydrate plugging and allow the formation of a hydrate slurry yielding flowable conditions.
Abstract Hydrates, solid crystals looking like compact snow (gas system) or slurry (oil system), are formed of water and gas at high pressure and low temperature (Figure 1) [1]. These conditions are usually encountered during shutdowns and restart operations in deepwater environment. Considering the associated production shortfalls and the cost of offshore remediation means, line blockage due to hydrates formation must be avoided [2]. And as a consequence, one of the main constraints in the design and operation of deepwater subsea developments has often been the management of hydrates in the production flowlines.
- South America > Brazil (0.46)
- Africa > Angola (0.29)
- North America > United States > Texas (0.28)
- Europe > France (0.28)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Inhibition and remediation of hydrates, scale, paraffin / wax and asphaltene (1.00)
- Facilities Design, Construction and Operation > Offshore Facilities and Subsea Systems (1.00)
- Facilities Design, Construction and Operation > Flow Assurance > Hydrates (1.00)
Summary A dry tree well in the Gulf of Mexico (GOM) has been producing oil with more than 50% water cut. This raises a concern, because the existing Anti-Agglomerants Low Dosage Hydrate Inhibitor (AA LDHI) used during extended shutdowns and cold restarts, is effective only up to 50% water cut. Because more time and resources would be required to bring a new AA LDHI, more detailed analysis were performed to evaluate the possibility of managing hydrate risks through operating procedures. It was found that during extended shutdown, the wellbore fluid can be pushed down below the mudline using the dry gas from the glycol contact tower followed by diesel or methanol. Thus, it eliminates the hydrate risk during extended shutdowns. Confirmed by the actual data, the cold restart simulations found the warm-up time in the wellbore to be less than an hour. The actual data also show the cumulative water cut one hour after restart was found to be below 50%. The cold restart procedures have been updated with the strategy to outrun the water and come out of the hydrate condition as quickly as possible. Since then, the well has been brought on production using the existing LDHI without any hydrate problems, even with a water cut approaching 90%. Introduction Under favorable conditions of high pressure and low temperature, hydrocarbons and water can combine to form crystalline solids, which resemble wet snow or ice, that are also called hydrates. The crystal structure is composed of cages of hydrogen bonded water molecules which surround "guest" hydrocarbon molecules such as methane, ethane, and propane. The thermodynamic stability of these structures increases as pressure increases and temperature decreases (Sloan 1998). These ice-like structures could agglomerate to block tubing, flowlines, and/or facilities. To determine the conditions of temperature and pressure under which hydrates can form, the best approach is to conduct experimental measurements on the appropriate hydrocarbon/water mixture. However, this is not always practical. Thus, the method for predicting hydrate behavior using thermodynamic models is more common. A thermodynamic model is used to calculate the hydrate equilibrium curve, also known as the hydrate disassociation curve. The hydrate disassociation curves for Well A-4 gas is presented in Fig. 1. The curves are generated based on gas composition given in Table 1. The reason to use the hydrate curve based on gas composition instead of combined reservoir fluid composition is to give more conservatism, although it was found that the difference between the two curves happens to be very small. The combination of pressure-tempreature (P-T) condition on the right side of the curve is safe, while the left side is subjected to hydrate formation. The curve shifts by approximately 15°F because of the 13.3% salinity of the produced water, which will have a major impact in flow assurance analysis. This shows the importance of having the accurate water chemistry analysis in generating the curves. Based on the saline hydrate curve and maximum shut-in wellhead pressure of 3,000 psia, the temperature in the entire tubing must stay above 60°F to be free from hydrate risks. To keep the operating condition of a well or a hydrocarbon production system free from hydrate risks, several techniques can be applied. Mechanically, the flow conduit along the production path can be insulated to keep the heat carried by the reservoir fluid contained within the flow conduit. However, depending on the overall heat-transfer coefficient of the flow conduit and the ambient temperature, the operating condition could soon enter into the hydrate risks condition during shutdown or restart. Thermodynamically, hydrate inhibitor (such as methanol or glycol) can be injected into the flow stream to shift the hydrate equilibrium curve to the left; thus, when the flow conduit cools down to the ambient temperature during shutdown or restart, it stays on the right side of the hydrate curve. However, shifting the hydrate curve to the left until the operating condition during any production scenario saved from hydrate risks might require an excessive amount of inhibitor that would then require larger injection and storage systems for that inihibitor. If the injection system, such as a pump or umbilical, is already in place and has limited capacity, well-production rates might have to be choked back to keep the effectiveness of the inhibitor. One of the possible solutions for this problem is by injecting a low-dosage hydrate inhibitor (LDHI). By definition, LDHI should be able to manage hydrate risks with a lower amount as compared to the conventional inhibitor such as methanol or glycol.