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The fault propagation of multistate systems (MSSs) with various operational modes is a critical factor affecting the reliability and safety of systems. However, traditional methods have difficulty describing the influence of function transitions and multiple faults of components on fault propagation, and are inapplicable for accurately evaluating the dynamic reliability of MSSs. To solve these issues, an agent-based method is developed to evaluate the dynamic reliability of MSSs. This study proposes a reliability modeling framework that consists of a management agent and several system agents. Combined with different agents, two types of models are established to describe the logical relationships among components. Moreover, Monte Carlo simulation is used to evaluate the dynamic reliability of MSSs, and a visual failure paths analysis method is proposed to inhibit potential risk. The LH4-1 horizontal Christmas tree is used to verify the effectiveness of proposed method. Under the designed working condition, the dynamic reliability curve of system with three operational modes and the visual failure paths including 15-node are obtained. By comparing the influence of failure rates, it is found that the production choke valve, flowlines, tree cap and MEG chemical control valve have a great impact on the system reliability.

High pressure pipeline transportation has been an established technology for economically transporting large amounts of CO2. However, there are still issues and associated risks that have to be effectively addressed and adequately understood. It is well known that a strong Joule-Thomson Cooling effect can occur when pressurized CO2 flows through a choke valve. Thus, to investigate the choking characteristics especially the temperature drop of high pressure CO2, a new laboratory scale experimental setup (total length of 14.85 m and the inner diameter of 15 mm) was constructed. Steady choked flow and transient choked flow tests were carried out respectively for pressurized CO2 in various initial phases. The phase transitions and temperature drop characteristics were then studied following the choked flow and the results show that the phase transitions in steady choked flow differs significantly from that in transient choked flow. For transient choked flow of various initial phases, all the flows downstream would transfer from single phase to gas–liquid two-phase flow. Furthermore, the effect of water on transient choked flow of supercritical CO2 pipeline was investigated, and the phenomena of solid particles deposition was captured which was paramount importance of ensuring the safety operation of CO2 pipelines when throttling by the choke valves.

The characterization of the multiphase flow through valves and orifices is a problem yet to be solved in engineering design, and there is a need for a prediction model able to simulate the complexity of this kind of flow in relation to fluid thermodynamic behaviour, and applicable to different incoming stream conditions and compositions. The present paper describes the development of a global model for the calculation of the discharge coefficient of orifices and choke valves operating under two- and three-phase flow as well as critical and subcritical conditions. The model generalizes the hydrovalve model developed by Selmer-Olsen et al. (in: Wilson (ed) Proceedings of 7th international conference on Multiphase Production, BHR Group, pp 441–446, 1995) and the Henry–Fauske (J Heat Transfer 93: 179–187, 1971. 10.1115/1.3449782) non-equilibrium model on the basis of an updated definition of the discharge coefficient. The model has been adapted to real choke valve geometries, by fitting the discharge coefficient and model parameters using field data from three production wells. The model developed is a global quartic function with different constants for the different valve geometries. The new discharge coefficient allows to simulate field data with high accuracy.

Slugging flow is a condition caused by a liquid obstruction at the riser base. It exhibits cyclic behaviour. The cycle consists of a protracted time of no gas production at the riser's top, followed by the arrival of a liquid slug with a length greater than the riser height, and ultimately the breakthrough of a significant gas surge. The cycle time might range from a few minutes to a few hours, depending on the system size and flow conditions. In offshore oil production, feedback control is a practical and cost-effective way to prevent slug flow. To control the flow rate or the pressure in the pipeline, adjusting the choke valve opening on the topside facility is generally utilised as the control input. From a practical standpoint, designing a control system based on topside data rather than seabed measurements is preferable. Controlling the topside pressure alone is difficult and ineffective in reality, but combining it with the flow rate results in a more reliable control solution. Measuring the flow rate of a multiphase flow, on the other hand, is difficult and expensive. All the topside measurements-based slug control techniques was critically reviewed and necessary recommendations for enhanced control performance provided. In conclusion, this review acknowledged that slugging is a well-defined flow pattern, yet despite having been studied for several decades, current slug control methods still have robustness issues. Slug flow problems are expected to become even more intense in the future as a result of longer vertical risers driven by deep-water Exploration and Production (E&P).

Managed pressure drilling (MPD) operation utilizes a fully automated control system to manage kicks during drilling which typically utilizes a proportional-integral (PI) controller and a single-phase flow model. This study proposes an MPD control system that uses a nonlinear model predictive controller (NMPC) and a two-phase flow model for computing annular pressure and choke valve dynamics during kick control operation. The performance of the proposed model is demonstrated by simulating kick control operation and compared their results with a single-phase linear model. The results confirm that the single-phase model underestimates key well control parameters (including kick size, bottomhole pressure and choke pressure), which may be due to ignoring gas-phase flow behaviour on mud density and the choke valve performance. Additionally, the performance of the proposed model is tested by validating the gas kick simulation results from a lab-scale MPD setup and a gas kick event from a field's case study based on North Sea drilling operation. The comparison of the control performance between the proposed NMPC model against the PI controller utilized in the field study confirms that the NMPC response more swiftly to disturbance, such as kick than the PI controller.

In offshore oil production, the occurrence of oscillatory flow regime that causes instabilities is very common, resulting in production losses, occasioned by shutdown, and environmental fine due to the violation of quality requirements. In this work, we evaluate the capability of a nonlinear model predictive controller (NMPC) integrated with an optimization layer to maximize production, minimize energy consumption and mitigate impacts caused by slug flow regimes present in offshore processes. The objective function used in the optimization problem is formulated with the oil and gas production as profit and energy consumption as cost. The degree of freedom of the optimization problem are the topside pressure in the processing plant and the gas-lift injection flow rate in each well. The constraints are the BSW (Basic and Water sediments) and TOG (Grease and Oil content) specifications, capacity of the compression unit and the limits of gas-lift injection, in each well and total flow. The simulated offshore production system encompasses the subsea well, the flowline, the riser, and the topside platform. The subsea part, with four wells, was modeled in OLGA simulator and integrated with a simulated platform in EMSO simulator. The control problem was formulated with nine manipulated variable: gas-lift injection and opening choke valve in each well, and interface level in the separator drum. The results show that the controller can reject the slug disturbances, keeping the BSW and TOG inside the limits and driving the process to the setpoints coming from the optimization layer.

Maintenance of subsea operating equipment is a significant part of the operational costs of running an oil production system. For instance, on the Norwegian continental shelf, it amounts to 60 billion NOK in operational expenses. One of the principal mechanisms of degradation in subsea process equipment is erosion by sand, which is a very complex process and, thus, difficult to model using physical domain knowledge. Because of this difficulty, we propose in this paper the use of data-driven approaches for modelling erosion in critical equipment of a subsea oil production rig. In such systems, a multitude of available process measurements such as flowrates, gas lift injection rates, pressures etc. can be combined to a soft sensor for component degradation. This approach could save significant amounts of resources by allowing fewer cost intensive inspections and monitoring schemes. A soft-sensor approach was tested with simulated data of the sand degradation of a choke valve in a gas lifted oil production system with three wells. In this paper, we present results from soft-sensor methods like multiple linear regression, regression trees, ensembles methods and kernel methods. The approaches were tested and compared in two case studies, the first with constant sand outflow from the reservoir for initial exploration of the data driven approaches, and the second with a more realistic profile in which the sand rate is increasing. In both cases, we compare the soft sensor modelling techniques in terms of their basic requirements of accuracy as well as transparency and interpretability.

Summary Hydrolyzed polyacrylamides are used as mobility-control agents in polymer flooding operations to improve the macroscopic sweep efficiency of the oil reservoirs. For this, very high molecular-weight polymers are often preferred to maximize their viscosifying power. In return, these long polymer chains are very sensitive to shear degradation which originates from chain stretching and breaking when the solution is subjected to a sudden acceleration. For a mother solution injection scheme, one polymer injection pump is normally installed on each well to inject tailored viscosities. The injection system avoids viscosity loss by injecting a high concentration polymer solution downstream the choke valve. One drawback of this setup, however, is that CAPEX, maintenance and energy demands are usually higher than for a valve-based scheme. In 2012, the development of a low shear valve suitable for polymer flooding was initiated. By employing unique spiraling flow channels with optimally designed reducer and expansion zones, machined on the surface of discs, shear forces and thereby polymer degradation is controlled. During a prototype test using a very shear-sensitive diluted polymer solution, presented in 2019, it was demonstrated that the polymer degradation through the new valve was less than 10 % at up to 45 bar pressure drop, compared with 60 % for a standard valve. In this paper, results from a field test of the novel low shear valve are presented. The low shear valve was installed on a high-concentration mother solution flow line at the Matzen field in Austria. At a flow rate of 1.6 m³/h and polymer concentration of 11800 ppm, the low shear performance of the novel valve was investigated at up to 35 bar pressure drop. Within the design range of up to 20 bar pressure drop, the viscosity degradation through the valve was not higher than 2.7 %. In conclusion, the low footprint valve was found to be easy to connect and operate, and the low shear performance was well within the design criteria. When employing the novel low shear valve in a mother solution application, the one-pump-per-well injection scheme can be replaced with a larger central pumping station plus one low shear valve per well to control the injection viscosity. In this case, the low shear valve has the same low shear performance as the positive displacement pumps. However, compared to the one-pump-per-well scheme, the central pumping station and low shear valves will result in significantly lower CAPEX and maintenance costs.

Oil production employing gas lift techniques enable the production of no natural flow wells and supply the energy lost in the reservoir caused by the field depletion, keeping the production in brown fields feasible. The multiphase flow conditions and the long pipes used to transport the fluids from the reservoir to the surface facilities, especially in deep and ultra-deepwater cases, may create unstable flow situations. Several publications in process control have discussed this problem since the 1980s, but the potential multivariable actions on the choke valve and gas lift flow have not been explored so far. In this paper the operating oil production system is treated through a nonlinear predictive control strategy. The strategy evaluation in a rigorous model (OLGA) shows the association between predictive capability and the integrated actuation in the manipulated variables results in an oil production increase and a partial or entire suppression of the instabilities in the multiphase flow. Furthermore, the rate of acting required on the valves is lower in the multivariable approach, allowing the use of slow choke valves as a final control element.

During drilling the mud flows through the drill string and exits through the choke valve. The mud density range has as constraints: pore pressure (minimum limit) and fracture pressure (maximum limit). In fact, annulus bottomhole (downhole) pressure needs to be higher than pore pressure, in order to prevent kick, and smaller than fracture pressure, for avoiding mud loss and formation damage. Experimental and simulation studies were implemented in order build a monitoring – diagnosing tool working together with a decision making routine based on an adaptive control scheme that employs gain scheduling. An experimental unit was built, presenting the most important characteristics of the drilling process. The transient nature of annulus bottomhole pressure is due to the process inherent disturbances: rheology, rate of penetration (ROP), kick and mud loss, which were all implemented at the experimental unit. The major objective of the present paper is using the experimental plant and a phenomenological model for implementing real time process automation, in order to assure drilling inside operational window, using in line measurements for flow and density disturbances under circulation loss and kick scenarios.

The flow rate values reported in real time, for an oil and gas production unit, refer to the total amount produced by that unit. On the other hand, data referring to the flow rate of each producing well in real time are usually not available, due to the difficulty in implementing flow measurement devices. These individual flows are determined by production tests that are generally performed every two months and are important for production planning and optimization. Therefore, there is a need to generate models capable of predicting the flow of each well in the period between tests, in order to identify possible issues during the production. In this context, we propose in this paper a method to predict the liquid and gas flow rates of each well as function of measured variables available in plant data collected in real time. Choke valve specifications and fluid properties are also required as model input data. Since there is no flow measurement device, it is not possible to directly validate the model results against plant data. In this case, the model validation is performed using the total liquid and gas flow rates presented in the Daily Operation Report (DOR) and those provided by fiscal meters. Relative errors below 3.5 % were observed, showing good agreement between the calculated flow rates and the provided by fiscal meters. The proposed method was implemented in the computational environment EMSO, which presents as advantages the low simulation time and robustness over a wide range of input data. These advantages become important as the model is used for monitoring platforms in real time. The range of applicability of this model can be attributed to the Gas-Oil Rate (GOR). In this work, the lowest and highest values of GOR considering all the wells are 207.58 and 393.97, respectively.

Feedback control is an effective and economic solution to prevent slugging flow regimes in offshore oil production. For this, the opening value of a choke valve at the topside platform is usually used as the control input to regulate the pressure or the flow rate in the pipeline. Designing such a control system based on topside measurements, without subsea sensing devices, is preferred from a practical point of view. Controlling the topside pressure alone is difficult and it is not robust in practice, but combining the topside pressure and the flow rate results in a robust control solution. However, measuring the flow rate of a multiphase stream is challenging and requires expensive instrumentation. In this paper, we propose an anti-slug control solution based on a virtual flow measurement. This virtual flow is estimated without neither density nor phase fraction involved, but it gives satisfactory results for the stabilizing control. In particular, applying a cascade structure results in a robust and recommended solution. The performance of the proposed controller is demonstrated by simulation using the realistic OLGA simulator and by experiments.

Erosion wear in pipelines due to multiphase flows is a well-known problem in the petroleum production and transport industries. There are several different ways to predict the erosion damage on the system investigated. Nevertheless, there are very few studies of erosion on choke valves and it is still unclear which models should be selected. Different geometries give different flow profiles and therefore different erosion patterns. Knowledge of where and what magnitude the erosion wear occurs is crucial to obtain efficient and economical production and choke valve design. In this research, computational fluid dynamics (CFD) with the Lagrangian modeling methodology, was used to examine the erosion wear on a choke valve in a pipeline. The first part of this thesis focused on finding the best-suited erosion wear model for the system. Furthermore, analysis of the impact of particle size and rebound coefficients was performed for the best-suited erosion models. To predict erosion wear using CFD analysis there are three main steps: flow modeling, particle tracking and calculating the erosion wear from the particle interactions. Masteroppgave i prosessteknologi PRO399 MAMN-PRO

Bušenje je kompleksan tehnološki proces, često popraćen brojnim problemima, a jedan od njih je i dotok, koji može dovesti do erupcije. Ukoliko se dotok pojavi, tada je potrebno isključiti isplačne pumpe, zatvoriti bušotinu pomoću preventera, iscirkulirati dotok kroz vod za prigušivanje bušotine, te ugušiti bušotinu utiskivanjem otežane isplake u svrhu vraćanja bušotine pod kontrolu. Vod za prigušivanje bušotine vodi prema razdjelniku podesive sapnice, na kojemu se nalaze ventili i podesive sapnice, a služi za smanjenje tlaka dotoka na atmosferski tlak, a nakon toga se fluid, otvaranjem i zatvaranjem ventila, usmjerava kroz tlačne vodove prema isplačnoj jami, vibracijskim sitima, separatoru plina ili baklji, ovisno o potrebi., Well drilling is a demanding technological process, usually followed by many problems, and one of those problems is the entry of the formation fluid into the wellbore, known as kick, which can eventually lead to blowout. If the kick occurs, it is necessary to shut down the mud pump(s), close the well by activating blowout preventers, circulate the fluid out through choke line, and kill the well by pumping heavy drilling mud into the wellbore. Choke line, connected to the drilling spool, leads to the choke manifold, on which valves and chokes are located, and its purpose is to reduce the fluid pressure to atmospheric one. After that, by opening and closing certain valves on the choke manifold, the fluid is directed through pressure lines either to the mud pit, shakers, gas separator or flare.

CO2 enhanced oil recovery (CO2-EOR) technique is one potential option that can not only limit global warming, but also cut the high cost of Carbon dioxide Capture, Storage (CCS). It is well known that Joule-Thomson cooling (JTC) can occur when multiphase mixtures flow through wellhead chokes. To predict the temperature drop for multiphase mixtures with high CO2 content through choke valves, a new multiphase choked flow model was developed, which was based on the isenthalpic model, gas-liquid solubility equilibrium model and gas-liquid thermal equilibrium model. At the same time, a verification experiment was carried out to study on the flow characteristics in multiphase choked flow. The results also showed that the model predictions were in good agreement with the experiment data and HYSYS simulation results. It was found that choke valve pressure drop, gas components and gas-liquid ratio had impacts on the JTC. The positive contributions to JTC for CH4, N2 and H2 were decreasing gradually and high mole fraction of CO2 can enhance JTC. Based on this study, low GLR, low pressure drop and high upstream temperature can prevent freeze and block of the pipeline downstream.

One of the main components in oil and gas production system is choke valve. The choke valve role is maintaining sufficient back pressure to prevent water gas coning and formation damage and also stabilizing fluid flow to reach the optimum production scenario. Chokes can be employed either on surface or subsurface to control the fluid flow characteristics to the downstream processing facilities such as flow rate, pressure, and velocity. Malfunction of choke may results in severe damages in safety, facilities, and environment. In this study, a rigorous method based on artificial intelligence is developed to predict the choke flow coefficient for subsonic natural gas flow through nozzle and orifice type chokes. Reynolds number and ratio of choke diameter to pipe diameter was utilized as input parameters. The method used in this study is radial basis function neural network coupled with genetic algorithm. The results showed great agreement with experimental data. In addition, the proposed method was compared with classic correlations. This comparison demonstrated the robustness and superiority of the GA-RBF model.

For as long as oil has been produced, techniques have been developed to control flow, and choke valves are an integral element of this vital requirement. This paper explores the history of the industry’s move from surface to subsea production and the translation of topside choke valve technology to the more challenging, underwater environment. It considers the types of valves available for different operating conditions and the importance of specifying a valve correctly to avoid early deterioration, costly maintenance or production outages. It explores the future challenges that the oil and gas industry faces and the advances in control valve technology that will support the ongoing development of seafloor processing techniques.

The bottom hole pressure should be controlled during the pipe connection procedure in a drilling operation to prevent the possibility of oil well blow out, to avoid the collapse of the well and to prevent the fracturing of the bore walls. It should be maintained within a window defined by the collapse pressure as the lower limit and by the fracture pressure as the upper limit. This paper describes the use of a nonlinear model predictive controller (NMPC) to maintain the bottom hole pressure. In addition to a topside choke valve, backpressure pump is also used as a control input. While connecting an additional pipe segment, the injection of the drill fluid is completely stopped. The drill fluid pulse telemetry system that is used in the measurement and transmission of the bottom hole pressure may not function properly and there will be absence of signal while the pipe is being connected. A nonlinear estimator, the unscented Kalman filter (UKF) is used for the continuous estimation of the fluid flows and pressures at different sections of the well being drilled. Simulation results show that the bottom hole pressure can be managed effectively during the drilling of an oil well with nonlinear estimation and control.

This work is an improvement of a previous work (Andreolli et al. 2018) by including a tubing as a subsystem of the pipeline–riser system, a realistic choke valve model to predict the two-phase critical flow and pressure drop before the separator and boundary conditions between stretches of the geometry, in order to improve the determination of the stability boundary. The improved stability solver is applied for a three phase flow (gas, oil and water). Stability for operational points obtained from actual measurements are successfully predicted with the stability maps generated by the solver considering the tubing connected to the Wet Christmas Tree (WCT). A parametric analysis is made in order to evaluate a choke valve influence over stability maps. The stability maps are built by using field conditions at Santos and Campos basins (Brazil). The numerical results present a good agreement with numerical data and real operational conditions. The analysis to evaluate and verify the choke valve influence over stabilization shows a good agreement with the expected behavior.

This paper analyse the failure of two choke valve inserts from offshore subsea service in the Northern North Sea. The choke valve stems were manufactured from Nickel-based superalloys 718 and coated with WC. The design life was 25 years. Treated seawater was injected at a rate of 5600 m3/d for about 3 years, and then water injection rate was increased to 7360 m3/d in next 4 years with an addition of produced water from the field. Maximum design flowrate for the choke was 8320 m3/d. The first choke was failed after about 7 years in operation. The choke was removed and replaced by a second choke of same design and material of construction, which failed after less than 12 months service. The failure occurred almost at the same location at the hollow stem section where pressure balancing port holes were drilled. The analyses were concentrated on the fractography as well as materials chemical, mechanical and metallurgical evaluation. All the materials examination demonstrated that the failed stem material complied with API 6A718 and had been heat-treated correctly. The diagnose shows that fatigue was the primary failure mechanism. Fatigue initiation occurred at a location on a port owing to particularly high local tensile stress concentration. The main drive of fatigue crack initiation and propagation, in this case, appears to be the loading cycle. Fractography (beach marks) indicated that high frequency low amplitude fatigue mechanism was active. The balance port is recommended to be moved to the top of plug where local tensile stress concentration is inticepated to be minimum.

The co-existence of gas, water, and monoethylene glycol (MEG) is common in produced fluids of high-pressure gas wells. Accurate predictions on the temperature changes during the choking process are essential for the design and operation of the choke valve. This paper presents an efficient multiphase isenthalpic flash method based on the cubic-plus-association equation of state (CPA EOS) to calculate the choke temperatures. In comparison with the traditional isenthalpic flash algorithm, this new method accounts for the self- and cross-association between polar water and MEG molecules, yielding more accurate enthalpy calculation results and multiphase component distributions for fluids containing water and MEG. The proposed model is validated by field test data with pressures from 8.68 MPa to 119.3 MPa. The average absolute deviations between the calculated choke temperatures and measured values are less than 1.6 °C even for vapor-liquid-aqueous three-phase mixtures at various pressures. Moreover, case studies show that accounting for the association between polar water/MEG molecules contributes to accurate predictions on choke temperatures. At high pressures, the CPA EOS tends to give higher choke temperatures in comparison with those calculated based on the traditional SRK-Peneloux EOS. In contrast, the CPA EOS tends to yield lower temperatures at low pressures.

Slug flow is a major problem to the structural integrity and production equipment in offshore production platforms. Pressure oscillations due to the alternation of liquid and gas phases in slug flow regime can cause fatigue on the structural components of the platform. Also, the intermittent high flow rates can cause adverse effects on the production equipment.A 28-foot pilot scale model was constructed to simulate the riser on offshore platforms. Three pressure sensors were attached to the model to monitor and record pressures in the riser during operations. A PID control strategy was utilized to regulate the pressure oscillations in the system by use of a linear actuated valve. Similarity between the pressure signals in the pilot scale model is qualitative when compared to actual pressures observed in an offshore riser system. A MATLAB® GUI was designed to allow for manipulation of the valve and allow for instant graphing of data for real time visualization of the pressure signals.Pressure oscillations during slug flow with “no control” vary greatly and result in natural vibrations of the designed system. By pinching down on the choke valve to a designated opening, the back pressure in the riser increased, thereby slowing down the liquid slugs. However, an increase in the magnitude of the higher frequency oscillations can have adverse effects on the system. With the implementation of an active control, such as a linear actuated valve, a better control of back pressure on the riser and reduction in the magnitude of the higher frequency oscillations on the system is achieved.Copyright © 2018 by ASME

In this paper, a new mathematical model is developed to accurately simulate the dynamic filling process of high-pressure tankers for marginal gas wells. The hydrodynamic and thermodynamic equations, and the thermodynamic properties of wet gas are assembled to represent the process elements, including gas wells, high-pressure tankers, connecting pipes and resistance elements (i.e., choke valves and heaters). Based on the damped Newton-Raphson method, a quasi-steady solution procedure is proposed to solve this model. The reliability of the proposed model is validated against experimental data obtained from a marginal gas well. The volumetric flow rate at the standard condition, the fluid velocity at the outlet of the choke valve, the fluid temperature and hydrate formation temperature after the heater are investigated. Moreover, the parameters including the mass flow rate, the charged mass, and the total filling time are calculated to determine the high-efficient filling period. The results show that the numerical results of present work are in good agreement with the experimental data. This model provides an effective approach to determine the maximum handing capacity, inlet and out diameters of the separator, and the outlet temperature of the heater. Also, the high-efficient filling period and the operation time of compressors could be obtained to optimize the number of high-pressure gas tankers and to enhance the economic benefits. This model could further be applied to the refueling process of compressed natural gas (CNG) or compressed hydrogen gas (CHG) in refueling stations by use of different equations of state (EOSs).

This work investigates the application of Nonlinear Model Predictive Control (NMPC) using Hammerstein Models in an offshore oil production well with gas-lift. The problem is especially challenging from the control point of view because it presents regions with gain sign inversion. This reversion of the gain direction makes this problem difficult to control with the usual Model Predictive Control (MPC) or even with the traditional Proportional-Integral-Derivative (PID) controllers. Thus, it is proposed to investigate the use of methodologies applying NMPC based on Hammerstein model combined with the Moving Horizon Estimator (MHE) approach. The oil flow rate is controlled by the gas-lift flow rate through the gas-lift choke valve. The plant was described by a mathematical model including the gas-lift well, the flowline and the production choke valve. Some control scenarios were tested and the nonlinear model predictive controller was capable to successfully stabilize the process.

This work presents a numerical study of the effects of mechanisms such as gas injection, choking and different boundary conditions on the stability of the stationary state for two-phase flows in vertical and catenary pipeline–riser systems. Numerical linear stability analysis is performed to a suitable mathematical model for the two-phase flows in a pipeline–riser system. The mathematical model considers the continuity equations for the liquid and gas phases and a simplified momentum equation for the mixture, neglecting inertia (NPW – no pressure wave model). A drift flux correlation, evaluated in local conditions, is utilized as a closure law. Gas injection and a choke valve are added, respectively, at the riser bottom and top. The extended model is applied to air–water pipeline–riser systems reported in the literature. Numerical linear stability analysis results are compared with experimental and numerical results reported in the literature with excellent agreement.

Estimation of individual phase flow rates in multiphase flow is of great significance to production optimization and reservoir management in oil and gas industry. This paper proposes radial basis function network to develop a virtual flow meter (VFM) that can estimate gas flow rate in multiphase flow production lines. The model is validated with actual well test measurements, and testing results reveal excellent performance and generalization capability of the developed VFM. The paper also discusses the significance of bottom-hole and choke valve measurements to attain accurate predictions. Proposed VFM model potentially offers an attractive and cost-effective solution to meet real-time production monitoring demands, and reduces operational and maintenance costs.

Active control has been recognised as one of the most promising methods to mitigate slugging by several researchers. However, choke valves used in offshore oil and gas production systems are often in a large size with a very large stroke time (time for a valve traveling from fully open to fully close or vice versa). This leads to not only a significant but also variable input time delay because the actual time delay also depends on the input increment value at each sampling point. In many practical offshore slug control systems, the large valve stroke time has been a major factor impacting significantly on the slug control performance. In this work, a modified Smith predictor is proposed to resolve this problem. Firstly, the traditional Smith predictor, which was mainly designed for fixed measurement time delay, is specially modified for variable input time delay using measureable delayed signal (actual valve position). Then, a linear model is adopted to present the slugging system without a time delay. Finally, the modified Smith predictor is implemented and tested using OLGA simulation software coupled with Matlab through OPC. Results show that the modified Smith predictor can significantly improve slug control performance when the choke valve has a large stroke time. With the Smith predictor, the system can operate at a larger valve opening, hence increase oil production.

Well production rate is a major factor for simulation of commingled gas wells. It is the base of computations of well flowing pressure, pressure drop, well performance, flow regime, liquid holdup, reservoir performance, material balance and average reservoir pressure. Typically, well flow rate is measured using flow meters like orifice, but in some wells flow rates remain unknown due to shortage of flow meters and commingled production. In this paper, well flow splitting of a gas-condensate field with two platforms is studied. Each platform consists of ten wells and wellhead pressure is controlled by a choke valve. Total flow rate of platforms mixed production is measured after sending their production to refinery. The proposed methodology for dividing total flow between wells consists of choke modeling using test separator data and flow modeling in the wells. Choke models include mechanistic and Ashford and Pierce as theoretical models and Gilbert, Ros and Pilehvari as empirical models. In most investigations choke size is represented with length unit such as inches but in this work, flow is calculated on the base of choke opening percent and choke size as a function of choke opening percent is obtained. Chokes are modeled with upstream temperature, upstream pressure and downstream pressure. Rich gas flow calculations with the proposed method were compared with reported total flow of platforms and showed mean absolute percentage error of 3.2% for mechanistic model as the best of studied models. This error can cause 0.5% error in calculated well flowing pressure. Sensitivity analysis on operation parameters showed that since the gas-condensate field is lean, gas flow rate is the major phase for modeling and uncertainty of gas-condensate ratio and changing specific gravity and molecular weight of condensate with time do not have considerable effect on well flow rate calculations.

For the reality of the variable pressure in the oil field, an adjustable disk choke valve is introduced in this paper. The structure and working performance of the valve is described in detail, too. The field application of the valve shows that the valve has such advantages as simple structure, quickly facilitate, easy installation and cleaning, long service life, safe and reliable, all these leads to the broad application prospect of the valve.

The process of transferring the natural gas from the gas well to the gas separation plant encountered some delay time depending on the distance between this well and the factory, the cross section of the transport line, the geometry of this transport line, the well pressure and others. To control the factory inlet pressure by controlling the choke valve existing at the well head, the delay time makes the traditional control systems to fail. In this framework we aim to solve this problem by presenting a novel controller design and delay modeling technique. The presented technique is compared to the previous control system design and delay approximation techniques.

A mathematical model and numerical simulations corresponding to severe slugging in air-water pipeline-riser systems are presented. The mathematical model considers continuity equations for liquid and gas phases, with a simplified momentum equation for the mixture. A drift-flux model, evaluated for the local conditions in the riser, is used as a closure law. In many models appearing in the literature, propagation of pressure waves is neglected both in the pipeline and in the riser. Besides, variations of void fraction in the stratified flow in the pipeline are also neglected and the void fraction obtained from the stationary state is used in the simulations. This paper shows an improvement in a model previously published by the author, including inertial effects. In the riser, inertial terms are taken into account by using the rigid water-hammer approximation. In the pipeline, the local acceleration of the water and gas phases are included in the momentum equations for stratified flow, allowing to calculate the instantaneous values of pressure drop and void fraction. The developed model predicts the location of the liquid accumulation front in the pipeline and the liquid level in the riser, so it is possible to determine which type of severe slugging occurs in the system. A comparison is made with experimental results published in literature including a choke valve and gas injection at the bottom of the riser, showing very good results for slugging cycle and stability maps. Simulations were also made assessing the effect of different strategies to mitigate severe slugging, such as choking, gas injection and increase in separation pressure, showing correct trends.

Slugging flow in the offshore oil & gas production attracts lot of attention due to it's limitation of production rate, periodic overload on processing facilities, and even direct cause of emergency shutdown. This work aims at two correlated objectives: (i) Preventing slugging flow; and meanwhile, (ii) maximizing the production rate at the riser of an offshore production platform, by manipulating a topside choke valve through a learning switching model-free PID controller. The results show good steady-state performance, though a long settling time due to the unknown reference for no slugging flow.

Passing the flow through a choke valve is one of the most important and valuable techniques in oil production. Liquid flow rate is an important factor to assess oil wells from an operational and economic point of view. There are some validated models that predict the flow rate of single phase fluid in a wellhead condition. However, the fluid is mostly multi-phase and lies in the critical condition when passing through the choke valve. A large number of scholars have made abortive attempts to develop a universal method to predict this flow rate. Based on the available empirical equations, the liquid rate depends on upstream pressure, gas-liquid ratio, and the bin size of the choke valve. To fill the current gap, this paper seeks to develop a model that can predict the multiphase flow behavior of choke valve in critical conditions by means of Radial Basis Function (RBF) neural network coupled with Genetic Algorithm (GA), as the optimizer. The model was developed using 221 training and 55 testing data points. The obtained results were then compared with the field data and, accordingly, the eligibility of the selected method was verified. Moreover, the dependency of input parameters on the liquid rate was evaluated using the Pearson and Spearman methods to show the effectiveness of each input parameter. While upstream pressure and gas-liquid ratio showed an inverse relationship, the choke bin size showed a direct relationship with the liquid rate.

Active control of the production choke valve is the recommended solution to prevent severe slugging flow at offshore oilfields. This requires operation in an open-loop unstable operating point. It is possible to use PI or PID controllers which are the preferred choice in the industry, but they need to be tuned appropriately for robustness against plant changes and large inflow disturbances. The focus of this paper is on finding tuning rules based on model identification from a closed-loop step test. We perform an IMC (Internal Model Control) design based on the identified model, and from this we obtain PID and PI tuning parameters. In addition, we find simple PI tuning rules for the whole operation range of the system considering the nonlinearity of the static gain. The proposed model identification and tuning rules show applicability and robustness in experiments on a test rigs as well as in simulations using the OLGA simulator.

In an Electric Submersible Pump (ESP) lifted oil field, the ESP of each oil well should be operated inside its operating window. The total power consumed by the ESPs in the oil field should be minimized. The speed of the ESPs and the production choke valve opening should be optimally chosen for maximizing the total oil produced from the oil field. At the same time, the capacity of the separator should not be exceeded. In this paper, nonlinear steady state optimization based on Sequential Quadratic Programming (SQP) is developed. Two optimal control structures are proposed in this paper. In the first case, the optimal pump speed is controlled by a PI controller by varying the electrical excitation signal to the motors. The optimal fluid flow rate through each oil well is controlled by another PI controller by varying the production choke valve opening. The paper shows that the production choke valve for each oil well has to be always 100% open to maintain the optimal fluid flow rate. In the second case, the production choke valves are considered to be always 100% open as hard constraints. The optimal fluid flow rate through each oil well is controlled by a PI controller by varying the pump speed. It is shown that when the optimal fluid flow rate is tracked by the controller, the speed of each of the pumps is equal to the optimal pump speed calculated by the optimizer. This basically means that we can achieve the optimization objective with the same optimal results as in the first case by using only a single PI controller. The limitations of these two optimal control structures for very low values and for very high values of the separator capacity are discussed. For the feasible range of separator capacities, the optimal locus of the fluid flow rate and the pump speed are shown in this paper.