Managed Pressure Drilling Research Articles

Gas kick dynamic circulation in MPD operations with water based drilling fluid: Maximum casing pressure modeling and validation

The use of water-based drilling fluids enables the rapid detection of a gas influx by pit gain monitoring due to the low solubility of gases in the aqueous medium. Moreover, as the influx remains as a free gas, it undergoes a process of expansion the further it rises through the well, changing the pressure profiles and producing a pressure peak when it reaches the surface. Therefore, the gas influx must be controlled appropriately. Otherwise, the maximum pressure experienced during the kick circulation may exceed the safety limits of surface equipment, placing the operation and the rig crew in a hazardous situation. The Managed Pressure Drilling (MPD) technique allows for a more precise detection and control of the influx while retaining the ability to circulate dynamically small volumes of gas kick through the riser, minimizing the risks involved and the non-productive time (NPT). However, the decision of when to apply dynamic or conventional circulation techniques must be considered carefully, taking into account factors such as predictions of pressure peaks, as well as intensity and volume of the kick. In this way, it is paramount that the maximum pressure during the circulation be estimated before the operation begins to ensure that the decision is made correctly. This paper presents the results of a gas kick circulation simulator specifically developed to predict pressure peaks. This simulator uses a mathematical model based on algebraic equations whose solution requires low computational effort and, therefore, regarding gas kick incidents, is an interesting tool that can aid in guiding decision-making. The results of pressure peaks were successfully validated by employing literature data, experimental drilling setup runs and simulations performed in a commercial software largely consolidated in the petroleum industry: Drillbench.

Unconventional Application of Managed Pressure Drilling

Unconventional Application of Managed Pressure Drilling

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.

Investigation of Backpressure Wave Propagation Properties during Gas Kicks in Managed Pressure Drilling

Summary It is often essential to provide backpressure to the wellbore by changing the opening size of the choke valve when a gas kick is detected during managed pressure drilling (MPD), which maintains the pressure in the bottom of the hole. In this study, a mathematical model was developed to explain how backpressure waves spread and weaken in a wellbore during MPD when there is a gas-liquid two-phase flow. The model is founded on a two-phase flow model, which thoroughly accounts for the gravity, shear force, and interphase interactions between the gas and liquid phases. The small perturbation theory was used to compute the backpressure wave’s propagation speed and attenuation coefficient. The outcome showed satisfactory agreement with other scholars’ experimental results. The model was used to study the impacts of the following variables on the backpressure wave propagation properties: void fraction, temperature, pressure, interphase resistance, shear force, density, invading gas composition, displacement of the drilling fluid, rate of intrusion of gas, gas-liquid surface tension, and drilling fluid viscosity. By using an example well, the laws of pressure wave propagation speed, attenuation coefficient, and propagation time with well depth were analyzed. Through evaluative methods in the field of economic management, the principal control variables governing the propagation of backpressure waves were determined. The conclusion is that, in terms of operational feasibility, lower drilling fluid density and reduced drilling fluid displacement are advantageous for a faster propagation of backpressure waves to the bottom of the well.

DEVELOPMENT OF PROJECT DOCUMENTATION FOR WELL CONSTRUCTION WITH THE USE OF MPD TECHNOLOGY

In traditional drilling technology, in order to prevent gas and oil-water blowouts, the pressure in the well should exceed the reservoir pressure by 5–10 % in static conditions, depending on the depth. However, in case of catastrophic sinking, drilling of highly permeable formations, narrow drilling windows in zones of abnormally high pressures such a safety method, on the contrary, often makes it impossible to drill the well. Today there are special systems to control the pressure in the well during deepening and circulation stops for drilling in difficult geological conditions. Their work is based on high-precision control of pressure in the annulus and its regulation at the sealed wellhead by means of an automatic choke in combination with a Coriolis flow meter. In static conditions, the required pressure is maintained either by an additional pump or by a nitrogen injector.Development of well construction projects requires reference to industry specific normative documents regulating the methodology of work, equipment selection and defining the minimum list of other technical and technological solutions necessary for quality and safe drilling operations. However, despite the fact that the technology of drilling with controlled pressure in different variations has been used in Russia for twenty years, there are still no regulatory documents summarizing the entire domestic experience of its application and regulating the procedure of drilling operations with controlled pressure. Their absence leads to certain technical risks and difficulties in passing departmental expert reviews of project documentation.This article analyses the rules and recommendations for well construction using managed pressure drilling technology contained in national industry regulatory documents, highlights the problems arising in the development of the technical part of the design and estimate documentation for the construction of similar wells, and gives recommendations on the composition of a regulatory document that could summarize national and foreign experience of managed pressure drilling.

Methods and experiments for automatic control of surface back pressure based on dung beetle optimizer-PID controller

To ensure safer drilling and to prevent kicks and blowouts, Managed Pressure Drilling (MPD) technology has been proposed. However, conventional MPD necessitates manual operation of the choke within the choke manifolds by engineers, a task heavily reliant on their experience. This paper proposes a PID controller tuned using the Dung Beetle Optimizer (DBO) and details several laboratory experiments on automatic choke control utilising DBO-PID alongside a modified hydraulic control box. The experimental results demonstrate that DBO-PID can quickly and stably control the surface back pressure (SBP) to the desired level. Following extensive laboratory experiments validation, a field experiment implementing DBO-PID with a hydraulic control box was conducted on an offshore platform. The field experiment results indicate that DBO-PID is 29 % faster than manual control by an engineer in stabilising the SBP, with an overshoot of less than 4 % when nearing the target SBP. Additionally, during the control processes for both constant and variably targeted SBP, pressure fluctuation was 72 % and 63 % less, respectively, compared to manual operation. Both laboratory and field experiments have conclusively demonstrated that the automatic choke control system, comprising DBO-PID and a hydraulic control box, can efficiently manage SBP, thereby preventing kicks and blowouts. Furthermore, this system could replace manual operations in MPD, enhancing the safety of oil and gas resource development, protecting engineers' lives, and safeguarding the natural environment.

Petroleum exploration and production in Brazil: From onshore to ultra-deepwaters

The Santos Basin in Brazil has witnessed significant oil and gas discoveries in deepwater pre-salt since the 21st century. Currently, the waters in eastern Brazil stand out as a hot area of deepwater exploration and production worldwide. Based on a review of the petroleum exploration and production history in Brazil, the challenges, researches and practices, strategic transformation, significant breakthroughs, and key theories and technologies for exploration from onshore to offshore and from shallow waters to deep–ultra-deep waters and then to pre-salt strata are systematically elaborated. Within 15 years since its establishment in 1953, Petrobras explored onshore Paleozoic cratonic and marginal rift basins, and obtained some small to medium petroleum discoveries in fault-block traps. In the 1970s, Petrobras developed seismic exploration technologies and several hydrocarbon accumulation models, for example, turbidite sandstones, allowing important discoveries in shallow waters, e.g. the Namorado Field and Enchova fields. Guided by these models/technologies, significant discoveries, e.g. the Marlim and Roncador fields, were made in deepwater post-salt in the Campos Basin. In the early 21st century, the advancements in theories and technologies for pre-salt petroleum system, carbonate reservoirs, hydrocarbon accumulation and nuclear magnetic resonance (NMR) logging stimulated a succession of valuable discoveries in the Lower Cretaceous lacustrine carbonates in the Santos Basin, including the world-class ultra-deepwater super giant fields such as Tupi (Lula), Mero and Buzios. Petroleum development in complex deep water environments is extremely challenging. By establishing the Technological Capacitation Program in Deep Waters (PROCAP), Petrobras developed and implemented key technologies including managed pressure drilling (MPD) with narrow pressure window, pressurized mud cap drilling (PMCD), multi-stage intelligent completion, development with Floating Production Storage and Offloading units (FPSO), and flow assurance, which remarkably improved the drilling, completion, field development and transportation efficiency and safety. Additionally, under the limited FPSO capacity, Petrobras promoted the world-largest CCUS-EOR project, which contributed effectively to the reduction of greenhouse gas emissions and the enhancement of oil recovery. Development and application of these technologies provide valuable reference for deep and ultra-deepwater petroleum exploration and production worldwide. The petroleum exploration in Brazil will consistently focus on ultra-deep water pre-salt carbonates and post-salt turbidites, and seek new opportunities in Paleozoic gas. Technical innovation and strategic cooperation will be held to promote the sustainable development of Brazil's oil and gas industry.

Overflow Identification and Early Warning of Managed Pressure Drilling Based on Series Fusion Data-Driven Model

Overflow is one of the complicated working conditions that often occur in the drilling process. If it is not discovered and controlled in time, it will cause gas invasion, kick, and blowout, which will bring inestimable accidents and hazards. Therefore, overflow identification and early warning has become a hot spot and a difficult problem in drilling engineering. In the face of the limitations and lag of traditional overflow identification methods, the poor application effect, and the weak mechanisms of existing models and methods, a method of series fusion of feature data obtained from physical models as well as sliding window and random forest machine learning algorithm models is proposed. The overflow identification and early warning model of managed pressure drilling based on a series fusion data-driven model is established. The research results show that the series fusion data-driven model in this paper is superior to the overflow identification effect of other feature data and algorithm models, and the overflow recognition accuracy on the test samples reaches more than 99%. In addition, when the overflow is identified, the overflow warning is performed through the pop-up window and feature information output. The research content provides guidance for the identification of drilling overflow and the method of model fusion.

Enhancing Offshore Drilling Efficiency through Multilevel Flow Modeling of MPD Operations

Exploiting all forms of energy must be coupled with the preservation of human safety and the environment. Despite the energy reserves beneath the ocean depths, challenging obstacles confront offshore drilling operations, notably the high pressure beneath the well. To comprehend this process better, we turned to modeling the managed pressure drilling (MPD) using multilevel flow modeling (MFM). These models provide a robust framework enabling us to understand and analyze the intricacies of this complex process. Our use of these models allows us to examine the causes and effects associated with various aspects of this process. All of this enables us to drill safely for the well, achieving our primary goal in this context.

Hydraulic modeling study and control algorithm design of double-layer pipe dual-gradient drilling

Deepwater drilling has the problem of narrow safe density window, and double-layer pipe dual-gradient drilling is one of the effective ways to solve the narrow safe density window. Due to the different structure and process principle with MPD, there is an urgent need to establish the hydraulic model and control algorithm of double-layer pipe dual-gradient drilling in order to realize the normal regulation of bottom hole pressure during drilling. Based on the hydraulic theory of managed pressure drilling and considering the influence of the three-channel structure of double-layer pipe and the downhole hydraulic lift pump in double-layer pipe dual-gradient drilling, a hydraulic model of double-layer pipe dual-gradient drilling has been established and verified in land well tests. Based on the double-layer pipe dual-gradient drilling hydraulic model, a control algorithm based on pressure regulation and flow rate regulation is established considering the principle of double-layer pipe dual-gradient drilling process. The simulation results show that the control algorithm based on flow rate regulation can greatly reduce the bottom hole pressure regulation time by controlling the size of the flow rate of the return fluid. When the bottom hole pressure is increased from 25 MPa to 26 MPa, the regulation time is 11min, which basically meets the requirements of field operation. The hydraulic model and control algorithm of double-layer pipe dual-gradient drilling are favorable to the bottom hole pressure regulation during drilling and reduce the response time.

Study Explores Challenges, Potential of Superlaterals in the Vaca Muerta

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper URTeC 3968851, “Breaking the 5-km Barrier: Superlaterals Delivery Challenges—Are They Feasible in Vaca Muerta?” by Julio Palacio, SPE, Walid Ben Ismail, and Richard Walker, K&M Technology Group, et al. The paper has not been peer reviewed. _ Driven by increased production rewards, multiple operators in the United States have been improving their unconventional wells by increasing lateral length. Several “superlaterals” with lengths greater than 23,000 ft have been drilled successfully in several US basins. The complete paper describes the technical challenges faced in drilling and running casing in superlaterals and the difficulties in implementing them in the Vaca Muerta unconventional play. Introduction In 2012–2015, many operators began to drill longer laterals. Because production did not appear to decline with increasing lateral length, one operator drilled 11 superlaterals in 2017 in the Utica shale, reporting critical cost reductions and a greater recovery per foot. This operator used the term “superlateral” to describe a lateral length of 15,000 ft or greater. At the time of writing, several wells have exceeded a lateral length of 23,000 ft and can be categorized as extreme-reach wells. Typically, any well in the extended-reach region requires a large focus on operational practices and may require important design changes and special technologies or techniques to achieve its goals. Geomechanics Challenges The Vaca Muerta/Quintuco system is a late Jurassic to early Cretaceous play with a depth of more than 8,200 ft true vertical depth (TVD). Pore pressure in Quintuco can vary between 14.2 and 18.8 lbm/gal. Fractures connecting different zones and depths lead to discontinuity and important uncertainties in both pore pressure and fracture gradient. Historically, Quintuco was isolated by running casing before entering the Vaca Muerta. However, several operators drill Quintuco and Vaca Muerta in the same section to reduce the well cost. Using this approach, Quintuco pressure uncertainties effectively limit the maximum lateral length. To reduce this uncertainty effect, managed pressure drilling (MPD) has been used successfully in current laterals. Bedding-plane instability limited early development of unconventional horizontal wells. Its effect is not commonly perceived while drilling but can affect bit trips and casing runs catastrophically. Higher mud weight (MW) has helped mitigate, but not eliminate, bedding-plane instability in unconventional plays around the world. However, higher MW can constrain more than the MW window requirements in the Quintuco/Vaca Muerta system. As the lateral progresses in length, the annular pressure increases proportionally. Given that the TVD remains almost constant in horizontal wells, the equivalent circulating density (ECD) change will increase proportionally to the lateral length. Because of this ECD behavior in horizontal wells, MPD cannot be used to manage the wellbore-stability (WBS) margin reduction in longer laterals or to eliminate pressure fluctuations during connections. In very long laterals, the only way to better manage the WBS margin, bedding-planes issue, and induced wellbore instability can be a well-design change to increase the annular clearance after performing extensive modeling. MPD and surface-parameter control can marginally help to control the problem.

Study on reliability of control system in deepwater CBHP MPD system

Deepwater managed pressure drilling technology, with unique advantages in dealing with narrow density window, has been widely used in deepwater drilling operations. As the key equipment to realize managed pressure drilling, the control system in constant bottomhole pressure managed pressure drilling system plays an important role in drilling operations. In this study, a new reliability evaluation method based on fault tree analysis and dynamic Bayesian network model has been proposed to analyze the reliability of the control system. First, the structure of the control system in the deepwater managed pressure drilling system was analyzed to set up a fault tree model of the control system. Second, considering the influence of time on the reliability, a dynamic Bayesian network model of the control system was established. Third, the proposed model was partly verified using the verification method based on three axioms. Fourth, in consideration of the repair factor, the reliability and availability of the control system were calculated by using the exponential distribution model of failure time. Finally, the sensitivity of the control system was analyzed, and the mutual information, variance and entropy were calculated to find out weak links in key components of the control system.

MODELLING OF DEEP WELL CEMENTING PROCESS

The research aims to simulate Managed Pressure Cementing (MPC) for a deepwater field, focusing on optimizing the cementing process to ensure structural integrity and wellbore stability. The study addresses the challenges associated with conventional cementing methods, providing insights into the pressure dynamics, fluid properties, and pump performance crucial for deep well cementing operations. The methodology involves conducting a simulation to model the cementing process for a deep well with a total length of 9144 meters, where the previous casing's shoe is located at a depth of 6096 meters. Real data is utilized to obtain profiles of reservoir pressure, hydraulic fracturing pressure, and viscosities of essential fluids, including cement, drilling fluid, and buffer fluid. The simulation considers factors such as annular pressure loss, Equivalent Circulating Density (ECD) calculation, and pump performance under varying conditions. Additionally, the density of the cement slurry in the annulus during pumping is established. The study reveals that pump performance under the given conditions is 57 m³/h for drilling and buffer fluids, while for cement solutions, it can vary from 19 m³/h to 38 m³/h. These results offer actionable insights for operational planning and optimization of the cementing process in deep wells. The simulation successfully models the cementing process for a deep well, providing valuable data on equivalent circulation density and cement slurry density in the annulus. The determined pump performance under different conditions is critical for understanding the dynamics of fluid circulation during cementing operations. Practical implications of the research include the optimization of cementing processes, contributing to enhanced structural integrity, reduced wellbore instability, and improved efficiency in deepwater field operations. In conclusion, the study not only contributes to theoretical understanding but also provides practical data for optimizing the cementing process in deep wells, reflecting the industry's commitment to continuous improvement in drilling technologies and ensuring the reliability and efficiency of wellbore operations in challenging environments. Keywords: managed pressure drilling (MPD), wellbore stability, downhole conditions, real-time monitoring, managed pressure cementing (MPC), zonal isolation.

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.

Heave attenuation in offshore managed pressure drilling with an integral sliding mode controller

Managed pressure drilling (MPD) is a technique used to precisely control the pressure within the wellbore during the drilling process to overcome drilling challenges, such as heave disturbance caused by waves. The mismatched nature of the heave disturbance presents a control challenge, making it difficult to reduce the disturbance effectively. However, MPD utilizing an appropriate controller can provide a solution to this challenge. As a result, this paper proposes an integral sliding mode controller (Integral SMC) based on feedback linearization and a nonlinear disturbance observer to attenuate the heave disturbance effect and provide stability for MPD systems. A comparison study is conducted between the proposed controller and industrial controllers, such as Proportional Integral Derivative (PID) and manual controllers, using root mean square error (RMSE) as the evaluation metric. Additionally, the robustness of the proposed controller and the nonlinear disturbance observer in the presence of parameter uncertainty and measurement noise is investigated. The results demonstrate that the proposed controller is a viable solution to overcome the heave disturbance effect on offshore MPD systems.

Improved gas influx distribution estimation using interfacial area transport equation (IATE) enabled two-fluid model: An advanced modeling and full-scale experimental study

Gas influx management is a critical aspect of petroleum drilling operations, which aims to prevent the uncontrolled outflow of formation gas and the potential consequences caused by blowouts. This study investigates the distribution of gas influx and the interfacial area concentration (IAC) during gas influx circulation operations through a combination of full-scale experiments and advanced numerical simulations.Experiments were conducted to simulate downhole gas influxes by injecting Nitrogen gas into the base of a 5,160-foot-deep experimental wellbore, which was filled with water. A Distributed Fiber-Optic Sensing (DFOS) system was installed in the wellbore to obtain high-resolution acoustic and temperature data and monitor the gas influx behaviors when circulated out of the annulus. Various types of measurements were obtained to analyze the gas influx length, slip velocities, void fraction distribution, and dispersion behaviors. In addition, an advanced numerical simulator was developed based on a modified Two-Fluid Model and the Interfacial Area Transport Equation (IATE) to simulate the gas influx behaviors. The model estimations were compared to the experimental measurements for validation of accuracy and further insights.The numerical modeling framework, based on the interfacial area transport equation, effectively captured bubble interactions, including mechanisms including bubble breakage and coalescence, by estimating the interfacial area distribution. The gas influx dispersion during circulation was analyzed using both model estimations and experimental data. Good agreement was observed between the model predictions and experimental data, including multi-depths gauge measurements and the DFOS data.This is a novel application of the IATE in well-scale multiphase flow simulations, which has proved to be an effective tool for predicting the dynamics of gas influx distributions. The outcomes of this study provide critical insights into the design and optimization of gas influx management during Managed Pressure Drilling (MPD).

A wellbore fluid performance parameters–temperature–pressure coupling prediction model during the managed pressure cementing injection stage

AbstractManaged pressure cementing (MPC) is a new technology based on managed pressure drilling, which has a greater advantage in facing narrow density window formations. However, the existing pressure prediction models during MPC injection stage consider fewer factors and have lower accuracy. To this end, combined with the characteristics of the injection stage, a predictive model of the distribution of annular fluid type was first proposed. Then, based on the experimental results, fluid density and rheology as a function of temperature and pressure were fitted. The governing equation of temperature‐pressure field was established. Eventually the fluid performance parameters–temperature–pressure coupling prediction model was developed in this paper. By comparing the predicted pump pressure with the measured pump pressure, the maximum relative error is not more than 10%. Using this model, the fluid type distribution, temperature field distribution, and pressure field distribution were investigated. The results indicated that the distribution of fluid types in the wellbore presented a complex variation, with up to 10 fluids in the casing and up to five fluids in the annulus. The trend of temperature field is complex, with three turning points. The larger the formation temperature gradient, the higher the fluid temperature in the annulus. The influence law of fluid heat conduction coefficient is reversed at 6750 m. Decreasing drilling fluid density will trigger gas channeling, while increasing drilling fluid density will increase the risk of fracturing formation, and safe operation can be realized by MPC. The variation of the static pressure in the casing is more complicated than in the annulus and the annular circulation pressure in the eccentric casing is smaller than that of the concentric casing, which is due to the smaller annular friction pressure. This study can provide a theoretical basis for the prediction of hydrodynamic parameters during the MPC injection stage.

Reservoir Drilling and Openhole Gravel Packing with High-Density Cesium Formate Fluids in a High-Pressure, Marginal Mud Window Environment at Martin Linge

Summary High-density cesium/potassium (Cs/K) formate fluids were successfully utilized from reservoir drilling to upper completion installation in five productive Martin Linge high-rate gas wells. Four wells were completed with openhole gravel pack (OHGP) and one with standalone sand screens. The gravel packing operation marks what is considered to be the highest density carrier fluid OHGP successfully completed worldwide, with a specific gravity (SG) of 2.06. A complex operation under pressure and temperature conditions (745–780 bar and 135–140°C) that almost qualify as high pressure/high temperature (HP/HT), including managed pressure drilling (MPD), overbalanced screen running, and openhole gravel packing, was simplified by using the same base brine throughout the operation. Cs/K formate reservoir drilling fluid (RDF) and screen-running fluid were designed with biopolymeric additives and minimal calcium carbonate bridging particles. Clear Cs/K formate brine was chosen as gravel pack (GP) carrier fluid. The use of Cs/K formate fluids for all stages of the operation reduced the complexity of transitioning between the operational stages. In addition, the reservoir was only exposed to one filtrate without application of damaging weighting solids. The drilling fluid contributed to successful MPD and delivered wells with very good hole quality in the reservoir, which consisted of interbedded sandstone, coal stringers, and shale. The shale-stabilizing properties of concentrated formate brine–based fluids provided acceptable conditions for extended openhole time and allowed additional logging runs, including pore pressure measurements, under near-HP/HT conditions, before running the screens. One bottom-up cleanout was conducted before the screen-running fluid was circulated in and the screens installed. The spurt and seepage losses were low throughout the drilling and screen-running phases. No breaker treatment was required in any of the wells. All wells have proved to have good initial productivity and high well productivity index. The successful OHGP operations performed with the high fluid densities required in Equinor’s Martin Linge field have set a new standard for well completions in challenging high-pressure environments.

Parameter and State Estimation of Managed Pressure Drilling System Using the Optimization-Based Supervisory Framework

Parameter and State Estimation of Managed Pressure Drilling System Using the Optimization-Based Supervisory Framework

USING SUPERVISED MACHINE LEARNING ALGORITHMS FOR KICK DETECTION DURING MANAGED PRESSURE DRILLING

Link for citation: Shcherbakov R.E., Kovalev A.V., Ilin A.V. Using supervised machine learning algorithms for kick detection during managed pressure drilling. Bulletin of the Tomsk Polytechnic University. Geo Аssets Engineering, 2023, vol. 334, no. 8, рр. 151-163. In Rus. The relevance. The depletion of readily available hydrocarbon reserves determines development of fields with complex geological environment. Managed Pressure Drilling marked the era of high-precision well parameters monitoring during drilling. This technology has provided access to deposits that were previously considered practically «unusable». The main goal of using managed pressure drilling technology is to control downhole pressure within specified limits in order to prevent fluid loss, fracturing, as well as unwanted kick of reservoir fluids into the wellbore. However, if for a certain period of time there is a kick of reservoir fluid from an open borehole or there are losses of drilling fluid, then it is not possible to control the downhole pressure within the specified limits. In this case, it is necessary to use an additional method or algorithm that marks such periods and indicates to the operator or the monitoring system about the presence of kick or absorption of drilling mud. The problems described earlier predetermined the aim of this work. It is claimed that the intelligent system can automatically monitor and analyze parameter trends, detect anomalies in the change of drilling parameters in real time, predict in advance the probability of formation fluid kick and warn the drilling engineer at an early stage, which will allow implementing preventive activity to maintain the required downhole pressure profile. The main aim: create the kick detection machine learning model which predicts kick probability during the managed pressure well drilling using mud logging service data. Objects: multivariate-sensing time-series data of mud logging and measured pressure drilling service. Methods: analysis and evaluation of anomaly detection techniques of determining kick during managed pressure well drilling using machine learning. Results. The authors have performed the overview of anomaly detection techniques of determining kick during managed pressure well drilling using machine learning. Classical machine learning algorithms were tested with labeled test data in order to evaluate its performance. The authors have developed kick detection model with gradient boosting algorithm, evaluated its performance with labeled test dataset. Promising areas of further research were identified.