Slug Catchers in Natural Gas Production - NTNU

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Karam – Slug Catchers in Natural Gas Production CHAPTER 6 HYSYS SIMULATIONS 6.1 Model Setup with a close up on the Ormen Lange case Aspen HYSYS V7.3 has been used to determine the continuous amount of gas, liquid and condensate. The simulations have been implemented for the four different fields in question. Therefore, data from all the fields had to be colleted and used as input for the simulation cases. The basis environment is built separately for every field, it includes all the fluid properties of that field. Afterwards, the flowsheet is built in order to connect the streams and the input data together. Many simplifications have been assumed due to the lack of accurate information. Ormen Lange is one of the fields to be investigated. As a first step, the composition of the field has to be determined in order to provide the simulator with the make up of the gas being investigated. The Peng-Robinson fluid package was chosen for the analysis. The model is attributed to a steady-state model which also reflects a simplified aspect of the model. For further simplifications, all wells and templates are also assumed to be symmetric in position and capacity. Wet gas has to be ensured in the reservoir and in its representation in the model. To do so, the reservoir gas stream has to be associated with a stream of water. These two are led to a simple vertical separation to extract the vapor phase which is used as the main reservoir stream. The initial reservoir conditions were specified in both the reservoir stream and the water stream. The reservoir temperature is 96 °C and the reservoir pressure is 290 bars. The setup of the field model is shown in Figure 16. The water flow rate has to be determined with precision. This is calculated by the water solubility r sw which is given in Kg/MSm 3 . A VBA has been prepared for that purpose where water mole fraction in methane and the water mole fraction in gas are calculated to get to the water solubility. The inputs to the VBA are the initial pressure and temperature, the gas gravity and the water salinity. The gas gravity in the case of the Ormen Lange is 0.6 as for the salinity, it is assumed to be zero ppm. The water mass rate, which is 1441 Kg/h, is obtained from the water solubility and the gas flow rate. It should be noticed that no formation water is produced at the early stages of production. The flow rate is one of the main and essential parameters to be included in the model as it affects the model’s performance to a great extent. The total gas flow rate of the field is 70 MSm 3 /d that are Page 26 of 56
Karam – Slug Catchers in Natural Gas Production produced from 8 different wells positioned symmetrically away from the PLEM. Two 30’’ pipelines transport the gas from the PLEM to the receiving terminals onshore. To simplify and due to symmetry, halving the wells and the pipelines can be used as a simplification according to Christiansen (2012) and Heskestad (2004). One well was enough to represent the flow through the wells. Therefore, the flow rate is divided by the number of wells which is thus 8.75 MSm 3 /d. The pressure drop in the reservoir, which is around 30 bars, was accounted for through a graph shown by Christiansen (2004). This pressure drop can be represented in the model through a valve. The Ormen Lange well is known as the Big Bore Well. It is a 9 5/8’’ tubing well with 8.5’’ inner diameter. It is not a vertical well. On the contrary, it has four different sections that are represented in a well elevation profile shown in the Figure 17. It can handle the largest production rates in the world and then can reduce the need for wells for the same production. As a next step, the flow will enter the pipeline passing first through a wellhead choke. The two 30’’ pipelines are 121 km long each with an inner diameter of 27.17’’. They are lying on the irregular and rough seafloor; therefore, a pipeline elevation profile is needed. It was taken from Christiansen’s paper (2012) and then digitized in HYSYS. The elevation profile to be digitized is represented in Figures 18while the digitized profile is shown in Figures 19. The wellhead choke should handle a pressure drop that will ensure the operational inlet pressure to the pipeline which is around 150 bars. The next spot to which the flow is heading to is located at the receiving terminal. The slug catcher is the first equipment to handle the arriving flow. It is represented by a simple separator in the model. It has a specific inlet pressure of 90 bars. A choke will be responsible for ensuring a pressure drop corresponding to the appropriate inlet pressure. As operations are carried on, the inlet pressure will be reduced to75 bars as production rate will decline to 60 MSm 3 /d (Gupta, 2012). An expected problem in the pipeline system is the formation of slugs. HYSYS allows the detection of such a hindrance; the slug detection should be activated in the model. This is done simply by ticking the ‘Do Slug Calculations’ option. The results are then displayed showing the slug position, the status, slug length, the bubble length, the film holdup, the slug frequency, the velocity and the pressure gradient. A sample of the results is shown in Figure 20. Page 27 of 56
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Slug Catchers in Natural Gas Production - NTNU

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