Wellhead Back Pressure Research Articles

Decision-making method of managed pressure drilling based on real-time calculation and analysis models

Abstract As petroleum exploration and development extend towards marginal, deep, and unconventional resources, drilling challenges such as narrow density windows and high wellbore control risks become increasingly prominent. Managed pressure drilling (MPD) proves effective in reducing drilling operational difficulties and well control risks in narrow safe-density window formations. However, existing MPD systems have limited capabilities for real-time calculation and analysis in the absence of downhole pressure measurement data, hindering accurate guidance for real-time calculation, analysis, and control decision recommendations in both conventional and precise MPD operations.Therefore, based on on-site engineering logging, real-time data from MPD operations, a branch decision tree was established to automatically determine the operational conditions of MPD. This achieved real-time identification of 11 drilling conditions. Starting from the characteristics of two-phase fluid flow in the annulus, coupling wellbore pressure and formation fluid invasion, a predictive model for annular pressure distribution during MPD was established. This model facilitated the calculation, determination, and recommendation of the pre-control value for wellhead backpressure. Building upon theoretical research, a MPD calculation, analysis, and control decision system was developed. Field testing and validation indicated that the system could simulate and analyze wellbore pressure and wellhead backpressure values, automatically identify drilling conditions and downhole complexities. The average error between the calculated and measured values of the standpipe pressure was 1.88%. The accuracy of the predicted wellhead backpressure values based on safe operating conditions compared to the actual controlled values reached 89.8%. This system achieved real-time calculation, analysis, and control decision-making based on real-time engineering parameters, enhancing the reliability and timeliness of wellhead backpressure control in MPD operations. It effectively guided conventional MPD operations and improved the capabilities and intelligence level of precision MPD operations after process optimization.

Research and Application of Online Electromagnetic Heating System with Internal Penetration in Oil Pipeline at Well Site

Abstract In response to the current situation of heating crude oil in the oil pipeline of Changqing Oilfield, most of the well sites have no associated gas, gas heating furnaces have been discontinued, and coal-fired heating furnaces pollute the environment. A study was conducted on the online through type heating system for the oil pipeline in the well site, with a focus on the composition and function of the digital heating system for the through type oil pipeline in the well site. The through type online heating system for the oil pipeline in the well site is mainly composed of a variable frequency electromagnetic controller The online controller and internal heating cable are composed of three parts. The oil pipeline generates heat by itself, while preventing the crystallization of paraffin and scale in the oil pipeline under the action of alternating electromagnetic fields, which is not easy to form wax. In 2023, on-site application was carried out on two oil pipelines in the Tongzhai operation area of the Third Oil Production Plant in Changqing Oilfield, replacing the existing gas heating furnaces and coal-fired heating furnaces to heat and transport crude oil in the oil pipelines. It does not generate heat itself and has a long service life. Due to the high thermal efficiency of the heat source coming from the inside of the oil pipeline, the buried pipeline renovation can be installed without breaking the soil. The flexible internal cable reduces the difficulty of construction and is safe and environmentally friendly, At the same time, it can remotely monitor the temperature of crude oil in the oil pipeline and the wellhead backpressure online.

Investigation on gas–liquid–solid three-phase flow model and flow characteristics in mining riser for deep-sea gas hydrate exploitation

In response to the problem of gas–liquid–solid three-phase flow in deep-sea hydrate extraction pipelines, a gas–liquid–solid three-phase flow model considering the dynamic decomposition of hydrates is established using continuity equations, momentum equations, and energy equations. The numerical solution of the theoretical model is achieved using the finite difference method. Comparing the theoretical model with the experimental results, the results showed that the average error of gas holdup, liquid holdup, solid phase content, gas phase velocity, liquid phase velocity, and solid phase velocity obtained from the theory and experiment are 8.24%, 0.41%, 1.88%, 5.80%, 2.81%, and 2.22%, respectively, which verified the correctness of the theoretical model. On this basis, the influences of hydrate abundance, liquid phase displacement, and wellhead backpressure on the gas–liquid–solid three-phase flow characteristics in the pipeline were investigated, and it was found that the gas holdup rate will increase with the increase in hydrate abundance, liquid phase displacement, and wellhead backpressure, with the influence of hydrate abundance being more sensitive. The liquid holdup rate increases with the increase in hydrate abundance and liquid phase displacement, but decreases first and then increases toward the wellhead position with the increase in wellhead backpressure. The solid phase content decreases with the increase in hydrate abundance, and first increases and then decreases toward the wellhead position as the liquid phase displacement and wellhead backpressure increase. The influence of gas phase velocity on the abundance of hydrates is relatively small, but it increases with the increase in liquid phase displacement. When the wellhead backpressure increases, the instantaneous increase then tends to flatten out. The influence of hydrate abundance on the liquid phase velocity is also relatively small, but it increases with the increase in liquid phase displacement and decreases with the increase in wellhead backpressure. The solid phase velocity will increase with the increase in hydrate abundance and liquid phase displacement, but it will not show significant changes with the change of wellhead backpressure. The research results can provide a theoretical basis for the safety of hydrate mining.

Mechanism of displacement gas kick in horizontal well drilling into deep fractured gas reservoir

The risk of well control is high when displacement gas kick occurs in the deep fractured reservoir, and improper handling can easily lead to blowout, which will seriously affect the deep well drilling. Using Fluent software, a simulation model was constructed to depict the interaction of a horizontal well with vertical fractures. The displacement gas kick process was simulated in horizontal well under formation temperature and pressure conditions. An analysis was conducted to assess the impact of fracture width, quantity, as well as the viscosity and density of drilling fluid on the process of gas-liquid displacement. It further compared the effectiveness of three measures in counteracting displacement gas kick: applying back pressure at the wellhead, altering the viscosity and density of the drilling fluid. New findings suggest that the gas-liquid interface within the fracture exhibits a funnel-like shape, where the gas and liquid phases are layered in the annulus and manifest in a streak-like pattern. Fracture width, quantity, and drilling fluid density promote displacement, while drilling fluid viscosity inhibits the displacement. Different from vertical wells, in horizontal wells, displacement gas kick mainly appears in the underbalanced interval. The fracture width primarily determines the size of the displacement window, while the density and viscosity of the drilling fluid exert lesser influence. Horizontal wells are highly sensitive to variations in external conditions when it comes to displacement gas kick. Therefore, enhancing the wellhead back pressure is advisable to address the displacement gas kick in horizontal wells.

Well Shut-In Pressure Determination Method for Deepwater Drilling Considering Fluid-Solid-Heat Coupling

Blowout is one of the most serious safety threats in deepwater drilling. Considering the characteristics of gas invasion in complex formations, gas migration and distribution, and dynamic changes in temperature inside a wellbore, a deepwater well-closing pressure determination method considering thermal-fluid-solid coupling was proposed. The model was verified using actual data, and the average error in the increase in casing pressure during the closing process was found to be 5.42%. The shut-in pressure of oil and gas wells under a transient shut-in process was analyzed. The results showed that the fluid thermal expansion caused by temperature recovery had a significant impact on the change in wellhead backpressure after well closure. Furthermore, the time required for the wellbore pressure to recover to the formation pressure varies nonlinearly with factors such as geothermal gradients, pit gains, bottom-hole pressure, and gas production indices. A pressure calculation chart was developed for deepwater drilling. The shut-in time for deepwater drilling should not be less than 15 min, and in cases where the gas production index is small and the bottomhole pressure difference is large, the shut-in time should exceed 90 min. The results can provide theoretical guidance and technical support for well shut-in processes during deepwater drilling.

Investigation on the propagation characteristics of pressure wave during managed pressure drilling

The small difference between formation pressure and fracture pressure in offshore oil and gas reservoirs poses a huge challenge to drilling. Managed pressure drilling (MPD) technology, as a drilling technique that can accurately control bottomhole pressure, is an effective technique to solve this challenge. In MPD technology, the pressure wave propagation behavior and mechanism in the wellbore induced by wellhead backpressure are crucial for parameter design and efficient application. In this paper, pressure wave propagation characteristics and mechanism in gas-liquid flow were investigated with a new proposed pressure wave velocity model that considers inter-phase mass transfer effect. This new model and its solution algorithm were verified with experimental data in literature. The influence of gas invasion stage, drilling fluid type, drilling fluid density and backpressure on pressure wave propagation characteristics were investigated. Results show that the time for pressure wave induced by wellhead backpressure in the wellbore cannot be ignored in the design of the backpressure value during MPD. This propagation time increases with occurrence of gas invasion. Moreover, the propagation time in water-based drilling fluid is longer than that in oil-based drilling fluid, which is because the interphase mass transfer between invaded gas and oil-based drilling fluid. The influence mechanism of high drilling fluid density and wellhead backpressure on pressure wave propagation characteristics is due to the suppression of gas invasion process. These findings could be used as guides in parameters design and optimization in MPD.

Effect of Instantaneous Starting Pump on Fluid Transient Flow in Managed Pressure Cementing

Abstract The fluctuating pressure generated by the instantaneous starting pump of cementing operation might easily cause formation fracture in narrow safety window formations. Accurate transient fluctuating pressure calculation and dynamically managed backpressure are required to achieve precise control of wellbore pressure in managed pressure cementing. Considering the transient flow characteristics of cementing fluids in the wellbore, unsteady transient friction, and the variation of high pressure-high temperature (HTHP) cementing fluid properties, a transient flow mathematical model of instantaneous starting pump during managed pressure cementing is established, and the method of characteristics is used for solution. Based on tht established model analyzes the magnitude and variation of wellbore pressure under different model factors, temperature conditions, pump start duration, and target pump flowrate, which can achieve more accurate analysis of transient flow. The pressure and flow fluctuations generated during the instantaneous starting pump of cementing are significant, and the dynamically managed wellhead backpressure can effectively control the wellbore pressure in the safe pressure window formations. This can reduce the risk of well leakage and provide reliable technical support for safe operations of instantaneous starting pumps during managed pressure cementing.

Chinese Few-Shot Named Entity Recognition and Knowledge Graph Construction in Managed Pressure Drilling Domain.

Managed pressure drilling (MPD) is the most effective means to ensure drilling safety, and MPD is able to avoid further deterioration of complex working conditions through precise control of the wellhead back pressure. The key to the success of MPD is the well control strategy, which currently relies heavily on manual experience, hindering the automation and intelligence process of well control. In response to this issue, an MPD knowledge graph is constructed in this paper that extracts knowledge from published papers and drilling reports to guide well control. In order to improve the performance of entity extraction in the knowledge graph, a few-shot Chinese entity recognition model CEntLM-KL is extended from the EntLM model, in which the KL entropy is built to improve the accuracy of entity recognition. Through experiments on benchmark datasets, it has been shown that the proposed model has a significant improvement compared to the state-of-the-art methods. On the few-shot drilling datasets, the F-1 score of entity recognition reaches 33%. Finally, the knowledge graph is stored in Neo4J and applied for knowledge inference.

An updated numerical model of fracture fluid loss coupled with wellbore flow in managed pressure drilling

The loss of drilling fluids often occurs during reservoir extraction in fractured formations, and the prediction of natural fracture loss rate is vital for controlling drilling fluids loss. However, the coupling of loss model to wellbore flow has rarely been considered. Based on the non-Newtonian fluid loss dynamics theory, this study considers Herschel–Buckley fluid and develops an updated numerical model to couple the loss of fracture with wellbore flow. The roughness of the fracture is characterized using the continuous random accumulation method. The coupling model is verified by field data, and its simulated results show the average relative and maximum relative errors were 4.76% and 12.8%, respectively. A linear throttle valve is introduced to simulate the effect of regulating wellhead back pressure and pump displacement on drilling fluids loss in managed pressure drilling, and the results indicate that the impact of regulating wellhead back pressure is better than that of pump displacement. This paper studies the pressure fluctuates of the fractured borehole breathing mechanism in detail and has proposed two possible scenarios that may cause borehole breathing. Increasing the wellhead back pressure can convert the overflow into loss, while reducing the wellhead back pressure by too much at once may also turn a loss into an overflow. The orthogonal experiment design is performed to study the influence of eight parameters on the loss rate, and the order of influence is as follows: fracture width, fluidity index, fracture area, consistency factor, yield stress, drilling fluids density, circulating displacement, and fracture dip.

Simulation study on multiphase flow considered seawater salinity in wellbore for deep-water bearing hydrate formation drilling

The gas-liquid-solid multiphase flow caused by decomposition of hydrate cuttings is a new problem facing the drilling of marine hydrate formations. In this paper, a gas-liquid-solid non-isothermal transient flow model is proposed considering the coupling relationships between hydrate decomposition, and heat and mass transfer in multiphase flow. The accuracy of the model in predicting gas void fraction, friction pressure and wellbore temperature is verified by using indoor experimental data and field measured data. Using this model, the influence of seawater salinity on the gas-liquid-solid flow behaviors is investigated. Numerical simulation results show that the decomposition area and decomposition rate of hydrate in the wellbore gradually increase with the increase of seawater salinity. Moreover, the higher the salinity of seawater, the greater the reduction in bottomhole pressure and the higher the decomposed gas void fraction reaching the wellhead. Increasing wellhead backpressure and lowering inlet temperature of seawater can effectively control the amount of hydrate decomposed in the wellbore. To ensure wellhead safety and reduce the rate of hydrate decomposition, the wellhead backpressure should be greater than 3.5 MPa. Compared with the wellhead backpressure of 2 MPa, the gas void fraction at the wellhead decreases 1.75 times when the wellhead backpressure is 5 MPa. When the seawater inlet temperature is in the range of 15 °C–30 °C, the seawater salinity control in the range of 8‰∼19‰ can manage the maximum gas phase volume fraction at the wellhead within 10%. Compared with the inlet temperature of 15 °C, the hydrate decomposition rate at the wellhead is 1.6 times higher when the inlet temperature is 30 °C.

A developed transient gas–liquid–solid flow model with hydrate phase transition for solid fluidization exploitation of marine natural gas hydrate reservoirs

The multiphase flow characteristic is one of the most concerning problems during solid fluidization exploitation of marine natural gas hydrate reservoirs. In this research, a new transient gas–liquid–solid multiphase flow model with hydrate phase transition was developed. Meanwhile, this model considered the coupling relationship among convective heat transfer, hydrate dynamic decomposition, and multiphase flow. The model can simulate the change of flow pattern from solid−liquid to gas–liquid–solid flow, and describe the distribution character of volume fraction of phase, wellbore temperature and pressure, and hydrate decomposition rate during transportation. The simulation results indicate that the hydrate decomposition region in the wellbore gradually expands, but the hydrate decomposition rate gradually decreases during the solid fluidization exploitation of hydrate. When mining time lasts for 4 h, and the bottom hole pressure decreases by about 0.4 MPa. Increasing NaCl concentration in seawater helps expand hydrate decomposition regions and improves the wellbore hydrate decomposition rate. When the NaCl mass fraction in seawater reaches 15%, it will raise the hydrate decomposition regions to the whole wellbore. In addition, the higher the wellhead backpressure, the lower the decomposition area and decomposition rate of hydrate in the wellbore. When wellhead backpressure reaches 2 MPa, the volume fraction of gas near the wellhead will reduce to about 12%. This work is expected to provide a theoretical basis for the development of marine hydrate reservoirs.

Simulation research on solid fluidization exploitation of deepwater superficial layer natural gas hydrate reservoirs based on double-layer continuous pipe

In this paper, a new method for exploiting shallow marine natural hydrate reservoirs is proposed using a double-layer continuous pipe. In order to research the multiphase flow behavior and hydrate decomposition characteristics during the hydrate mining process, a non-isothermal transient gas-liquid-solid multiphase flow model is established considering the coupling effect of multiphase flow, heat transfer and hydrate phase transition. The model's accuracy is verified by comparisons with laboratory and field data. Numerical simulation results show that the hydrate decomposition is slow in the first 2 h of mining, thus the volume fraction of each phase in the pipe changes little; with the increase of time, the volume fraction of each phase in the pipe changes significantly until it reaches a stable state after about 5 h of mining. When the mining rate exceeds 15 kg/s, the hydrate particles will not be fully and effectively transported, and a short time aggregation phenomenon will occur. Increasing the temperature of the injected seawater is beneficial to promote the hydrate decomposition, which in turn increases gas production. While, increasing the wellhead backpressure and seawater displacement facilitates in reducing gas production. The research findings will be of reference value for gaining insight into studying complex multiphase flow behaviors involving hydrate phase transition and provide a new approach to exploiting subsea shallow natural gas hydrate reservoirs.

Multiphase throttling characteristic analysis and structure optimization design of throttling valve in managed pressure drilling

As the key equipment to achieve accurate control of wellhead pressure during managed pressure drilling, the throttle valve can ensure the bottom hole pressure accurately controllable during the migration of invading gas in the annulus. At present, most of the research focuses on the throttling characteristics of single-phase fluid, and the research on the pressure regulation characteristics of throttle valve under the condition of multiphase flow is still relatively weak. In this paper, the mathematical model and CFD model of multiphase flow in the throttle valve are established, and the multiphase throttling characteristics under different hydraulic parameters are studied. The rationality of the proposed model is verified by field full-scale experiments. The results show that throttling pressure drop shows a nonlinear trend with the opening, which is not conducive to field application. Furthermore, through the sensitivity analysis of the throttle characteristic curve under multiphase flow conditions, the geometric structure of the throttle valve core is optimized to realize the fine adjustment of the wellhead back pressure under multiphase flow conditions, which is of guiding significance for wellbore pressure control under gas invasion condition.

A dynamic managed pressure well-control method for rapid treatment of gas kick in deepwater managed pressure drilling

During deepwater managed pressure drilling (MPD), the gas kick may occur in abnormally high-pressure formations. If the traditional well control method is adopted, the treatment time is long and the advantage of early gas kick detection of MPD is lost. The dynamic managed pressure well-control (MPWC) method can be used to rapidly treat gas kick in deepwater MPD. In this paper, considering the effect of large-variable-diameter annulus and complex wellbore temperature in deepwater drilling, a simplified model of non-isothermal gas–liquid two-phase flow was established for dynamic deepwater MPWC simulation. Using this model, the response characteristics of outlet flow and wellhead backpressure were investigated. The results indicated that the gas fraction, outlet liquid flow rate, pit gain and wellhead backpressure presented complex alternating characteristics when gas moved upwards in the wellbore due to the large-variable-diameter annulus. The outlet liquid flow rate would be lower than the inlet flow rate and the pit gain would decrease before the gas moved to the wellhead. The variation trend of the wellhead backpressure was consistent with that of the pit gain. When the gas–liquid mixture passed through the choke, the expansion or compression of the gas caused part of the choke pressure drop to be supplemented or unloaded, delaying the response rate of the wellhead backpressure. The wellbore temperature, borehole diameter and seawater depth had different effects on outlet flow rate, pit gain and wellhead backpressure. This research could provide a new idea for well control methods in deepwater managed pressure drilling. • A simplified model of non-isothermal gas-liquid two-phase flow is developed for deepwater managed pressure well-control. • The large-variable-diameter annulus leads to complex alternation of the responses of outlet flow and wellhead backpressure. • The expansion and compression of the gas cause part of the choke pressure drop to be supplemented or unloaded.

Risk and preventive strategies of hydrate reformation in offshore gas hydrate production trials: A case study in the Eastern Nankai Trough

Hydrate reformation in offshore gas hydrate production trials is an important issue that can readily cause flow blockage accidents, resulting in the termination of production trials. Previous studies on hydrate flow obstacle were mostly focused on conventional oil and gas production or transportation. However, there is a knowledge gap on prediction and management of hydrate reformation risk in gas hydrate production trials. In this study, a fully coupled thermal and multiphase flow model was developed to evaluate the risk of hydrate reformation in gas hydrate production wells, considering its specially designed well configuration and depressurization strategy. Model predictions were in good agreement with field monitoring data. A thorough analysis on the issues of hydrate reformation in twice offshore production trials of the Eastern Nankai Trough was conducted for the first time. The results indicate that in AT1-P and AT1-P3 wells, there is a greater risk of hydrate reformation in the water line (WL) and no risk exists in the gas line (GL); however, the hydrate reformation risk is also encountered in the GL of AT1-P2 well because wellhead backpressure and lower depressurization amplitude were implemented. Moreover, a series of sensitivity analyses were conducted with different well design and production parameters. It reveals that the hydrate reformation in the WL is inevitable unless complete downhole gas-liquid separation is achieved, but that in the GL can be completely prevented by raising the depressurization amplitude to above 6 MPa. Additionally, a new hydrate management strategy by rationally configuring wellbore pressure and improving thermal utilization efficiency was proposed. It has proven that new method enables to fully eliminate the risk of hydrate reformation in the production well without the used of the hydrate inhibitors. This work provides valuable references and practical implications for future short-term or long-term offshore gas hydrate production trials.

Managed Pressure Drilling Technology: A Research on the Formation Adaptability

Existing pressure drilling technologies are based on different principles and display distinct characteristics in terms of controlling the pressure and degree of formation adaptability. In the present study, the constant bottom hole pressure (CBHP) and controlled mud level (CML) dual gradient drilling methods are considered. Models for the equivalent circulating density (ECD) are introduced for both drilling methods, taking into account the control pressure parameters (wellhead back pressure, displacement, mud level, etc.) and the relationship between the equivalent circulating density curve in the wellbore and two different types of pressure profiles in deep-water areas. The findings suggest that the main pressure control parameter for CBHP drilling is the wellhead back pressure, while for CML dual gradient drilling, it is the mud level. Two examples are considered (wells S1 and B2). For S1, CML dual gradient drilling only needs to adjust the ECD curve once to drill down to the target layer without risk. By comparison, CBHP drilling requires multiple adjustments to reach the target well depth avoiding a kick risk. In well B2, the CBHP method can drill down to the desired zone or even deeper after a single adjustment of the ECD curve. In contrast, CML dual-gradient drilling requires multiple adjustments to reach the target well depth (otherwise there is a risk of lost circulation). Therefore, CML dual-gradient drilling should be a better choice for well S1, while CBHP drilling is more suitable for well B2.

Managed wellhead backpressure during waiting setting of managed pressure cementing

Managed pressure cementing (MPC) has been successfully used to reduce risk lost circulation and improve cementing quality in wells with a narrow safe pressure window. However, during the waiting setting period of MPC, the magnitude of the managed well backpressure is still based on experience, which results in a high risk of leakage or gas channeling especially in formations with a narrow safe density window. Therefore, a backpressure managing method is proposed here based on a model we built for calculating wellhead backpressure. This model was used to analyze the effect of cement slurry, temperature and wellbore pressure on wellhead backpressure. The results show that hydration, filtration shrinkage and gel supporting are essential to reduce wellbore pressure, although hydration is less effective compared with the latter two on pressure reduction. The magnitude and duration of wellhead backpressure depend on the extent of volume shrinkage and the gel strength development of cement slurry. Latex-cement slurry requires minimal wellhead backpressure with the shortest duration. Temperature and wellbore pressure greatly impact wellhead backpressure with temperature playing a more dominant role.

Wellbore Temperature and Pressure Field in Deep-water Drilling and the Applications in Prediction of Hydrate Formation Region

In the process of deep-water drilling, gas hydrate is easily formed in wellbores due to the low temperature and high pressure environment. In this study, a new, systematic, and accurate prediction method of temperature, pressure, and hydrate formation region in wellbores is developed. The mathematical models of wellbore pressure and transient heat transfer are established, the numerical solution method based on fully implicit finite difference method is developed, and the accuracy is verified by comparing with the field measured data. Combined with the hydrate phase equilibrium model, the hydrate formation region in wellbore is predicted, and the sensitivity effects of nine factors on wellbore temperature, pressure, and hydrate formation region are analyzed. Finally, the influence regularities and degree of each parameter are obtained. The increases of circulation time, geothermal gradient, displacement of drilling fluid, and injection temperature will inhibit the formation of hydrate in wellbores, and the influence degree increases in turn; the increases of wellhead backpressure and seawater depth will promote the formation of hydrate in wellbores, and the influence degree increases in turn. The changes of drilling fluid density, well depth, and hole deviation angle have little effect on the formation of hydrate in wellbores.

Transient two-phase flow behavior in wellbores and well control analysis for sour gas kick with high H2S content

ABSTRACT Complex two-phase flow phenomena in wellbores after sour gas kick may lead to severe well control incidents. By bridging the gas solubility, H2S phase transition and flow equations, a two-phase flow model is established under conditions of transient and non-isothermal states in wellbores, which is well validated against the two-phase flow experimental data. The following conclusions are drawn in the article: (1) a higher dissolved quantity and larger density of invaded sour gas containing H2S and CH4 in drilling fluids makes the detection of gas influx with high H2S content more difficult at an early stage; (2) when the mixed fluids move up to the wellhead, the release of the dissolved gas, the sharp decline of density of sour gas and the phase transition of H2S reduce the annulus pressure and induce complicated well control risks; (3) during H2S and CH4 influx, there are five major parameters that impact the bottom-hole pressure, which are evaluated for well control analysis. The proposed model shows a strong capacity to exhibit proper control of the wellhead back pressure, which can help to prevent the phase transition of H2S and reduce risks to well control.

Research on remote intelligent control technology of throttling and back pressure in managed pressure drilling

In order to reduce the non production time of drilling, improve the efficiency and safety of drilling, improve the economic effect of managed pressure drilling (MPD), and realize the intelligent control construction of digital oilfield. Based on the pressure control in MPD, this paper analyzes the pressure control drilling system, takes the wellhead back pressure as the controlled parameter, calculates the mathematical model of the throttle valve according to the characteristics of the throttle valve, the basic parameters and boundary conditions of pressure control drilling, and puts forward an improved particle swarm Optimization PID neural network (IPSO-PIDNN) model. By means of remote communication, VR technology can realize remote control of field control equipment. The real-time control results of IPSO-PIDNN are compared with those of traditional PID neural network (PIDNN) and traditional Particle Swarm Optimization PID neural network (PSO-PIDNN). The results show that IPSO-PIDNN model has good self-learning characteristics, high optimization quality, high control accuracy, no overshoot, fast response and short regulation time. Thus, the advanced automatic control of bottom hole pressure in the process of MPD is realized, which provides technical guarantee for the well control safety of MPD.