The Turner model is widely used in industry to estimate critical gas velocity to flow a gas well and unload its liquid content under steady state conditions. The Zhou model introduced improvements to the Turner model by taking into account the influence of total Liquid (condensate and water) to Gas Ratio (LGR) on critical gas velocity. While fairly acceptable at low LGR, current models do not address the impact of liquid holdup on wellhead flowing conditions and subsequent changes in critical gas unloading rates. Multiphase modeling is used in this study to validate the applicability of current models at various wellbore conditions and LGR. This study finds important applications in offshore and onshore gas field developments because it provides moe reliable assessment especially for gas fields in the depletion phase, or when liquid breakthrough occurs resulting in high LGR. Dynamic simulations indicate that at low to moderate LGR existing models under predict critical gas flowrate because they under estimate critical velocity, especially at high wellhead pressures, and don't take into account the impact of increasing liquid holdup on gas flowrate. Moreover, an inversion in critical flowrate occurs at very high LGR because the film holdup is sufficient to restrict the flow of gas and offsets any increase in critical velocity at such high LGR. The onset of liquid loading (well choking) is associated with the transition from annular to churn/slug flow. This is well demonstrated from the calculated trends of entrained droplet holdup. The significance of the current work to our understanding of critical flow in gas wells is illustrated by utilizing a multiphase simulator to better characterize the impact of entrained droplet and film holdup on critical flowrate and by predicting the inversion in critical gas flowrate at high LGR. The results of this study provide an enhanced understanding of well loading during all development phases and various production conditions to evaluate the applicability and accuracy of widely used models in a broad range of well conditions and liquid loads.

A new subsea tieback in the Gulf of Mexico (GoM) is expected to experience temperatures as low as 10 o F in the system due to high levels of expansion cooling. The system will operate within the hydrate region, at a high degree of sub-cooling. Current test methods used to select and determine the effectiveness of Low Dosage Hydrate Inhibitors (LDHIs) are capable of evaluating at temperatures down to 39 o F. A new test method was developed to effectively evaluate the performance of LDHIs at temperatures as low as approximately 10 o F.The flowline for the subsea tieback is un-insulated and the flexible riser is partially insulated by the layers in the construction of the pipe. The fluids will experience expansion cooling due to the Joule-Thomson effect as they move up the riser and will not be able to adequately take advantage of the "warm" surrounding seawater. As a result, the lowest expected temperature in the system is 10 o F. This lower temperature also means a higher degree of sub-cooling. Typically, the higher the subcooling, the higher the dose rate required to inhibit hydrates using an LDHI. To date, there is no data supporting antiagglomerate low dosage hydrate inhibitors (AA-LDHIs) are effective with black oils at operating temperatures between 10 o F and 30 o F. A new test method was required to show that an AA-LDHI will effectively inhibit hydrates at the system conditions of the subsea tieback.A description of the new test method used to evaluate AA-LDHIs at temperatures below 39 o F will be presented as well as the results. The results include the evaluation of produced fluids with and without the addition of AA-LDHI. These results demonstrate that hydrate formation and the effectiveness of AA-LDHI to inhibit hydrate blockage can be detected at low temperatures using the new test method. It is shown that the AA-LDHI effectively inhibits hydrate blockage at approximately 10 o F. It is also demonstrated that the mixture of produced water and AA-LDHI will not freeze at system temperatures.

Gas lift is being utilized to enhance production of heavy crude from the Campos field offshore Brazil. Downhole chemical injection is implemented to treat the crude and assist with chemical inhibitor delivery to protect the reservoir fluids in the well tubing from corrosion due to elevated concentrations of hydrogen sulfide (H2S). Due to the absence of dedicated chemical injection lines in the field, H2S scavenger is diluted in ethanol and transported with the gas lift, through the gas lift line (GLL), to the well casing. The gas lift and aqueous chemical phase flow together in the inner annulus between the casing and tubing as a multiphase mixture. The mixture is then injected into the well tubing through a gas lift valve (GLV). Field measurements have shown the crude is not always uniformly treated with the chemicals due to unsteady discharge of the chemicals from the casing into the production tubing through the GLV. Advanced steady state and transient simulations were carried out to analyze the supercritical / multiphase flow in the gas lift system. Moreover, the complex phenomena associated with the hydraulic instability upstream of the GLV, and subsequent irregular injection of the multiphase mixture into the tubing, were well-characterized. Simulation results are qualitatively accurate and descriptive as they duplicate the phenomena observed in the field. It was found that the dynamic stability of the wellbore was disturbed by either insufficient pressure gradients at the GLV or by localized slugging initiated in the casing. As such, chemical accumulation in the casing and intermittent pressure build-up upstream of the GLV were responsible for the non-uniform injection into the well tubing. The system’s dynamic stability can be restored by either increasing the casing pressure to a level high enough so the GLV tolerates normal variations in the casing pressure or by manipulating the flow pattern in the casing to avoid slug flow. Simulation results proved both techniques to be effective. Field data and simulation results show that GLL may be substituted for chemical injection lines provided the GLV is designed based on a sound understanding of the system’s hydraulics and a reasonable prediction of the operating pressures on its sides throughout the well life. Findings from this study provide guidelines for proper flow assurance practice and safe design and operation in artificial gas lift and chemical injection applications

The increasing demand for energy contributed significantly to recent developments in offshore production and transportation of oil and gas. Offshore oil spills are major threat to environmental safety and marine life. Damage control and preparedness planning require better understanding of oil spill process, trajectory, and how Metocean and atmospheric forces influence the spatial and temporal spread of oil in seawater dramatically. Computational fluid dynamics (CFD) has proved to be an invaluable tools to analyze in detail the dispersion of pollutants, including oil, in sea shore area. However, CFD models for large scale domains, extending several kilometers offshore and along the coast, need grids with several millions of points to accurately predict the dynamic distribution of spilled oil. For such large scale domains, over simplification of the physical model or Metocean data may result in significantly different results. A detailed Computational Fluid Dynamics (CFD) based study is established to predict the trajectory of oil film during various spill scenarios in shallow water wave profile and the influence of wavelength and amplitude as well as current velocity. A three phase (Oil, water and air) Volume of Fluid (VOF) multiphase model in ANSYS FLUENT is used to capture the free surface and the motion of oil film. It is found that in the absence of sea current effects, buoyancy of oil droplets is dominant, and the diffusion-advection on the surface continues to progress forming thick oil slick even in the opposite direction of the wave transmission. Higher wavelength (less frequent) are associated with less extent of oil dispersion since shorter waves (more frequent) will cause relatively more violent water flow near sea surface which can transport oil droplets further up in wave direction. Furthermore, waves of smaller amplitudes cause more spread of the oil slick, especially in the direction opposite to wave direction. This is because less amplitude waves are associated with less turbulence and breaking energy, and hence less dynamic vertical dispersion of oil film in seawater. IntroductionOffshore production of oil and gas is growing significantly due to the constant increase in demand for energy and recent advances in offshore technology. Oil spill into seawater is likely to occur due to major incidents such as a pipeline failure or offshore well blowout. The discharge and transport of oil from a spill source at the sea bed to the sea water and eventually to the sea surface is a very complicated phenomenon, in which many parameters influence the oil motion and distribution. This paper presents the influence of wavelength, amplitude, and sea current velocity on the transport of spilled oil through water column and the spatial spread and thickness of an oil slick on the sea surface. The following discussion illustrates how accurate presentation of surface waves and sea current can affect the modeling of offshore oil spill. Tkalich, P. et al. (2003) developed a Multiphase Oil Spill Model (MOSM) to simulate ...