An experimental study of a gravity-driven downhole separator for a pumped horizontal or deviated well is presented in this study. It considers the effects of the upstream flow, gas and liquid flow rates and deviation angles on the global separation efficiency and the free gas at the pump intake. The efficacy of downhole separators is typically tested under steady-state conditions where the fluids are injected above the separator. A new outdoor facility, which allows the injection of a two-phase mixture below the separator was designed, constructed, and used in this study. Gas and liquid flow rates and deviation angle are varied to study the liquid holdup in the liquid-rich outlet and the separator efficiency. The experimental results demonstrate the effects of the operation conditions and deviation angle on the behavior of downhole separators. It is found that the separator has two regions of performance; namely, high efficiency region and a region where the efficiency decreases with the liquid flow rate. Moreover, the effect of the deviation angle affects the results. The findings provide conditions under which and where the separator can be operated efficiently in the field.
The need for monitoring individual well production in unconventional fields is rising. The drivers are primarily related to accurate reporting for production allocation between wells. The main driver in North American operations for a meter-per-well flow rate monitoring has been the need for accurate per well production accounting due to the complexity of the land-owner interest.
There are additional benefits from the monitoring of early decline and determination of the transient evolution of the reverse productivity index (RPI) to evaluate the well performance. The availability of long-term rate transient data supports decline analysis and rate transient analysis, leading to better understanding of the estimated ultimate recovery (EUR), which may drive the selection of infill drilling locations. Finally, the identification of interference between flowing wells can help mitigate the issues of parent/child wells.
A specific case in the Eagle Ford is the systematic deployment of full gamma-spectroscopy multiphase flowmeters at well pads. This intelligent pad architecture consists of one multiphase flowmeter per well and a production manifold that enables commingling of the production to a single flowline connected to the inlet manifold of the production facility.
The rationale of the decision for the installation of such solution in lieu of a metering separator per well is based on the evaluation of the impact of this technology on capex and opex reductions.
Several lessons learned are provided. They include a discussion of the change management issues related to the installation of the meters, the modifications necessary to the production facility at the receiving side, and the data management and data analytics that were enabled from the gathering of systematic, continuous, and high-resolution measurements.
The impact of the installation of the meters in the field is noticeable and quantifiable. with several prior wells used as a benchmark. The effects are not limited to cost reduction, but also lead to an increase in production related to the release of operational crews from daily well testing tasks that used to be necessary. The data quality and coverage are also increased.
A few suggestions are made concerning optimization of the deployment and use of remote monitoring options for enhanced efficiency. Automated data workflows are also discussed.
The reduction of HSE risks through a better management of field operators is also assessed.
Recent advances in data acquisition systems have helped in monitoring wells performance and recording their production parameters like pressure, temperature and valve opening in real time with high frequency. A cost-effective technology to estimate well production rates is Virtual Metering, which integrates real time data and analytical models. This paper presents the methodology of an innovative virtual metering tool and the promising results obtained in real case applications on gas, gas condensate and oil fields.
A Virtual Metering tool has been developed by integrating a commercial software platform and mathematical models (algorithms). The algorithms solve simultaneously dynamic pressure and temperature gradients (VLP) along with the choke equation to find the optimal solution rates that match physical sensor readings. Moreover, the tool manages the communication between real time data and the models enabling a safe storage of the results. Models require a manual calibration at reference dates based on well separator tests or MPFM readings, in a way to match total field production. After calibration, the algorithm is able to run automatically in real-time.
Three implementations are presented about gas, gas and condensate and oil fields, showing the benefits and limitations of virtual meter application. Virtual meter proved to be a valid technology with the potential of even replacing MPFM results, especially in dry gas fields. Where MPFM are installed on each wellhead, virtual meter worked as redundant system and allowed to detect precociously flow meters malfunctioning. The allocation workflow has been modified in order to replace MPFM estimations with virtual meter ones. For oil fields with variable production parameters, the tool has provided reliable independent rate estimation by combining VLP and choke calculator in a unique optimization tool. The real time flow rate can be used as a basis for pro-rata allocation of fiscal production in the framework of a Production Data Management System software. Additional features of the tool are the following: a real-time input for pressure and rate transient analysis and a workflow for real-time well drawdown estimation of gas wells, which makes use of automatic p/z reservoir model update to estimate reservoir pressure. Moreover, this tool had a significant impact on production monitoring, improved the effectiveness of production optimization actions and the quality of history match of reservoir 3D model.
This paper contains a novel approach of a reliable and robust virtual metering tool that can be flexibly applied to gas and oil fields through a unique optimization algorithm, which is able to combine information coming from production network and from the reservoir side. It gives benefit to company workflows by feeding external reservoir analysis applications that would not be possible without virtual meter results and uses the results of external applications for validation purpose.
This paper's focus is the advocation of utilising diagnostic data available from digital field devices to help reduce operating costs for end users.
In recent years companies across multiple industrial sectors have invested in improving their understanding of both the historical and live data they produce. The source of the data is specific to the processes but the objective for all remains the same - to use statistical techniques to develop a toolset that can be used to predict performance based on live and historical data.
For the oil and gas industry, the continued adoption of digital device transmitters has increased the volume of data available from instruments such as flow meters, temperature probes and pressure sensors. Typically, this additional data provides information on the integrity or quality of the associated device. However, with the appropriate level of facility and instrument knowledge it is also possible to infer information with respect to the process stream.
Furthermore, this data, if correctly interpreted, can be used to predict maintenance and calibration requirements, resulting in reduced staff effort and shutdowns. The need for physical intervention due to device failure is also reduced, which in turn minimises the potential for accidental hydrocarbon release when a device is removed for repair or replacement.
NEL are currently undertaking research projects with the primary objective of developing definitive correlations between process effects, meter condition and diagnostic data response. The paper provides details of said research, with particular reference to the data science and mathematical techniques currently being trialed for the analysis stage. The techniques, when fully developed, will be metering technology specific and therefore offer a level of insight to end users on facility and meter performance which is not currently available in industry. The toolsets developed will in turn provide the end users with the knowledge and confidence to make cost saving decisions with respect to planned maintenance as well as improving facility efficiency through a more comprehensive understanding of their own data sets.
Saudi Aramco studied such algorithms to produce images simulating the flow inside a pipe’s cross section, possibly reducing the need for separator-based multiphase flowmeters. A former technical manager with Petrobras discusses the development of the company’s flow assurance philosophies and strategies. Looped lines are used to reduce pressure drop and increase flow capacity, but information on the flow behavior or predictive methods are not available for these systems. Bypass pigging has advantages over conventional approaches. Its application to multi-phase flow with high wax content crude is discussed.
Virtual metering technology has been in use for years as a cost-effective means of monitoring production, but what else can it do? How reliable is it as a backup to physical multiphase meters? Can Automation Speed Up Project Delivery? The execution of process automation projects depends on the completion of tasks that are not necessarily related to automation, hampering project development timelines. How do automation solutions, such as digital twins, help to overcome these challenges?
Megaprojects have come to define many of the world’s new resource projects but they are also a testament to the awesome engineering capabilities of the oil and gas industry. Find out who took home this year’s honors. The new deal covers production deck manifolds and subsea pipelines for Zuluf and Berri, two large fields undergoing expansion projects. The agreement calls for the two companies to partner on techno-economic feasibility studies and jointly assess investment opportunities across the LNG value chain. Saudi Aramco studied such algorithms to produce images simulating the flow inside a pipe’s cross section, possibly reducing the need for separator-based multiphase flowmeters.
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