The objective of the paper is to present the application of a transient multiphase flow simulator for the purpose of modelling and improving understanding of complex well behaviour which is not possible with a steady-state solution. The outcome was optimizing well production performance of problematic wells in terms of slugging flow and water loading at high network pressure in a gas condensate and oil field. Continuous reservoir pressure decline, increasing gas-oil-ratio (GOR) and water cut have led several wells in the field to exhibit slugging flow. Different intervention trials in the subject wells failed to bring the well online in continuous flow. The methodology employed was to construct the well model in a transient multiphase flow simulator using the available data; well completion schematic, compositional PVT fluid properties, and well test data. The fluid was characterised using the PVT package. The well model was built, and its performance was matched to dynamic natural slugging flow, shut-in conditions, clean-up operations, and artificial lifting case where nitrogen was injected via coiled tubing to lighten the wellbore fluid density. The modelling results of the well performance analysis have explored crossflow between reservoir zones and water loading phenomena on long sub-horizontal oil producers, at high operating well head pressures, as the cause of flow instability. The multi-stage completion and multiple reservoir intervals, with differing reservoir properties, were captured during construction of the well model. The static fluid gradient survey analysis verified the simulator outcomes, and this in turn proved its applicability for the complex fluids. The well model provided deep understanding of fluid flow in the wellbore for flowing and static conditions. The model was used to evaluate well intervention scenarios to establish a stable flow regime. These studies highlighted the possibility to achieve optimal operating well head pressures to avoid aggravating water loading and stable production process. Various multiphase stable flow optimization methods were examined along with an economic assessment. The dynamic multiphase flow simulator has been found useful in reproducing complex flow behaviour observed in problematic wells and improve stable production. The approach of using a transient multiphase flow simulator on wells with water loading issues and also with crossflowing intervals is vital, and this first time application has proved beneficial for the Karachaganak gas condensate and oil field.
The objective of this article is to demonstrate recent results of a water cut measurement campaign in the Karachaganak oil and gas condensate field. Historical, inaccurate well water cut assessment was due to the limitations of well test facilities which led to uncertainty in short- and long-term production forecasts. Several approaches were conducted to eliminate uncertainties in water cut measurements and to evaluate and define adequate tools to use for future water cut analysis. The use of a mobile sampling flow loop installed at the well head, where turbulent multiphase flow is guaranteed, was a safe and reliable approach to measure the water cut of the producing low and high productivity wells. Sampling and analyzing the fluid at the well site at various operating well head pressures, frequently and for long periods of time, resulted in better understanding of water cut dependence with changes in drawdown. In addition to the use of sampling on site, the optical sensor (OS) technology was a trial tested on two wells along with the sampling flow loop to confirm the accuracy of the technology. The existing test separators were not designed to handle high water rates; moreover, due to the complexity of the produced hydrocarbon, multiphase flowmeters are not able to accurately measure the correct fluid phase contribution and, as a result, inaccurately estimate phase rates. The OS tool demonstrated accurate real-time water cut readings in the liquid phase, when compared with the flow loop samples, as long as a turbulent flow is guaranteed during measurement. Thus, this technology can be considered as an accurate tool for water cut measurements. The possibility of temporary and permanent installation of the optical sensor tool at the well site or test lines is under evaluation. The current field development focuses on improved recovery from the oil rim which is above a weak aquifer. In the historically developed areas of the field this aquifer is separated from the hydrocarbons by impermeable shale and therefore water production has been minimal. Current and future development requires the drilling of new wells in areas not protected by barriers; this has led to a number of recent wells having a relatively early water breakthrough. As a result of accurate water cut measurements, unallocated water in the field was well defined and led to better control of water producing wells to maintain stability of process facilities. This application confirmed the limitations and low level of accuracy of the existing well test separators. The successful campaign to improve water cut assessment was critical to update and re-evaluate production wells’ operating philosophy, reservoir management, and the future development strategy of the carbonate reservoir.
Hydrocarbon production is commonly associated as the dispersed flow of two and more immiscible phases starting from porous media to surface facilities. In the dispersed flow, one phase is usually dispersed into another dominating phase in terms of droplets. Accurate prediction of the droplet size distribution of a dispersed phase is critical in characterizing complex flow behavior in pipe flows. In the first part of this paper, we provide the analyses of open-source experimental data on the maximum droplet size in gas-liquid annular flow and evaluate the existing theoretical models and suggest an improvement based on the experimental data analyses to predict the maximum droplet size of the entrained liquid droplets in gas-liquid annular flow. In the second part of this paper, we cover the experimental results from the open-source literature data and in-house experimental data to give the general understanding on droplet formation concepts and evaluate the existing predictive models and present a new modeling approach to determine a maximum stable droplet size of the dispersed phase in the liquid-liquid dispersed flow under turbulent flow conditions.
Understanding emulsion evolution at static conditions is crucial for pipeline operations during shut-in and startup and separator optimal design. This study experimentally investigated the temporal and spatial evolution of oil-water emulsion characteristics at static conditions, which include rheological behaviors, droplet size and distribution, water-cut/density, and stability. Emulsion samples were created in a mixer at ambient conditions, which were transferred into graduated glass cylinders where the volumes of separated phases were measured at different times. Phase density, rheological behavior, and droplet sizes were also measured at different times and positions in the cylinders. Isopar V and tap water were used as the testing fluids and Span80 as the surfactant. Four water cuts, two mixing speeds, and two surfactant concentrations were investigated. Experimental results showed that the apparent viscosity of the emulsion layer increased significantly with time and the shear-thinning behavior became more obvious over time. The emulsion apparent viscosity also variated vertically along with the glass cylinder. These phenomena were believed to be related to water volumetric fraction which was estimated from density measurements. The results showed that the water cut (or density) in the emulsion layer increased with time and eventually plateaued out near the inversion point, consistent with the rheological behaviors. Besides, it was observed that the droplet sizes increased with the depth, which could contribute to the gradually stronger shear-thinning behaviors. The water-in-oil emulsion became less stable at lower water cuts, lower surfactant concentrations below CMC, and slower mixing speeds. It was observed that lower surfactant concentration or slower mixing speed resulted in faster separation, leading to a faster increase of the apparent viscosity and density of the emulsion layer.
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