Gas Kick Research Articles

Transient Open‐Closed Loop Experimental Validation of a Nonlinear Two‐Phase Flow Distributed System

AbstractThe oil well drilling process is a nonlinear system with transient nature. Conventional drilling is unable to assure safe and cost‐effective operation for fractured, cavernous, and highly permeable carbonate reservoirs, which contain the largest oil reserves worldwide. Concerning drilling technologies, Pressurized Mud Cap Drilling (PMCD) is suitable for the challenging scenario previously mentioned. According to PMCD technique, a sacrificial fluid is injected through the drill string and a light annular mud is pumped in countercurrent through the annulus region (bullheading), without surface return, forcing gas and drilled cuttings back to formation. A two‐phase flow distributed model (Drift Flux Model – DFM) is developed to properly describe the complex nature of the system. Also, an experimental facility, presenting field similarity, is employed to validate the open – closed loop schemes. The main objective of the controller (control reconfiguration with gain scheduling) is to regulate annulus pressure, handling gas kick, drilling fluid losses and inverse response dynamics. Besides, gas injection, migration and bullheading are studied. The simulations, validated through experimental data, highlight the methodology usefulness for field applications.

Rheology assessment and barite sag in a typical North Sea oil-based drilling fluid at HPHT conditions

The occurrence of barite sag in drilling fluids has relatively often been the cause for gas kicks in oilwell drilling. The subsequent absorption of gas into drilling fluid could lower the density and reduce the viscosity of the drilling fluid, thereby aggravating both pressure control and hole cleaning. In this paper, we present experimental measurements of rheological properties and barite sag in a typical North Sea oil-based drilling fluid at downhole pressure and temperature conditions. A new experimental apparatus was setup for barite sag measurements at static condition with operational temperature and pressure capabilities up to 200 °C (392°F) and 1000 bar (14,503.8 psi), respectively. Rheometry measurements were conducted on fluid samples with and without barite particles at operating conditions up to 90 °C and 100 bar. We observed that at a typical shear rate of 250 s−1, which is experienced in 8.5″ hole annulus, the viscosity of fluid sample with barite increased nearly three times as that of the fluid sample without barite as the temperature and pressure increased. However, temperature effect on viscosity dominates at high shear rates compared to pressure effect. Furthermore, the fluid samples showed more shear-thinning effect with increasing yield stress as the temperature increased. On the other hand, barite sag measurements revealed that whereas fluid samples under high pressure are less prone to sag, high temperature fluid samples, however, promote sag significantly. The data from this study are useful to validate extrapolations used in computational models and to improve understanding and operational safety of sag phenomena at downhole conditions. We also discuss the importance of this study in optimizing drilling operations.

Gas-hydrate interpretation from 3D seismic attributes: An example from the Gulf of Mexico

Gas hydrates are a recognized drilling geohazard. If not mitigated, they may result in plugged blowout preventors, gas kicks, blowouts, borehole instability, gas leaks outside casings, and inadequate cementing operations. Gas hydrates located within the gas-hydrate stability zone (GHSZ) are difficult to interpret solely from seismic amplitudes. In this paper, we apply a multifaceted approach using the velocity pullup method in combination with 3D visualization of seismic attributes for the interpretation of gas hydrates within the GHSZ. The approach is applied to an area in the eastern part of the Gulf of Mexico in water depths greater than 2400 m. The practical outcome of this study is the choice of safe drilling locations outside of areas where gas hydrates have been interpreted to be present.

Development of a multiphase variable mass flow model and its application in well control for variable gradient managed pressure drilling

A multiphase flow model is an important foundation for well control simulation. In this paper, a multiphase variable mass flow model considering sudden density change was developed for variable gradient managed pressure drilling (MPD) and it was solved by finite difference method (FDM). Further, the model was used to simulate the whole process of well control based on constant bottom-hole pressure for variable gradient MPD. In this way, the advantages of the new gas kick detection method compared with the mud pit increment detection method and the variation laws of key parameters in the whole well control process were investigated. The results indicate that under the condition of small gas rate, the new gas kick detection method is better than the mud pit increment detection method because of its time savings. In the process of gas discharge, the wellbore pressure fluctuates due to the influence of gas expansion, sudden density changes at the separator position and annulus diameter changes at the casing shoe and mud line. The time when the back pressure reaches the maximum lags behind the time when the gas front reaches the wellhead. The mud pit increment increase rate when the gas front reaches the separator position is significantly higher than that in the early stage of gas kick detection.

Numerical Simulation of Gas-Liquid Gravity Displacement in Vertical Fractures during Drilling of Carbonate Formations.

In petroleum drilling, carbonate formations characterized by natural fractures can result in troublesome gas-liquid gravity displacement, which refers to the phenomenon that the drilling mud leakage and gas kick are simultaneously triggered. This work focuses on clarifying the mechanism of gas-liquid displacement in vertical fractures during the drilling of carbonate formations and investigating the characteristics of gas-liquid displacement under various conditions. First, the bottom hole pressure allowing for gas-liquid gravity displacement is analyzed, which determines the coexistence condition of leakage and kick in vertical fractures. Then, a theoretical model of gas-liquid displacement flow in a vertical fracture is established. To verify the reliability and accuracy of the model, the results of numerical simulation are compared with those of a visualization experiment. The development process and flow characteristics of gas-liquid displacement in the fracture under different conditions are numerically simulated. The effects of pressure difference, drilling mud property, and fracture geometry on the gas-liquid displacement rate are analyzed. It is found that the drilling mud leakage rate increases with the increase of fracture width, fracture height, and drilling mud density, while it decreases with the increase of pressure difference and fracture length. The gas invasion rate increases with the increase of fracture width, fracture height, and pressure difference, while it decreases with the increase of drilling mud density and fracture length. The equations for leakage rate and gas invasion rate are derived by the response surface method, and the methods for mitigating gas-liquid gravity displacement are discussed. It is expected that the present work provides a better understanding of the gas-liquid gravity displacement in carbonate formations.

Detection methodologies on oil and gas kick: a systematic review

Detection methodologies on oil and gas kick: a systematic review

Investigating Injection Pressure as a Predictor to Enhance Real-Time Forecasting of Fluid-Induced Seismicity: A Bayesian Model Comparison

AbstractFluid-induced seismicity is now a growing concern in the spotlight and managing its risks entails a probabilistic forecast model suited to real-time applications, which commonly relies on the operational parameter of injection rate in a nonhomogeneous Poisson process. However, due to potential injectivity change, gas kicks, and other processes, injection rate may not provide as robust a proxy for the forcing process as injection pressure, which embodies fluid–rock interactions. Hence, we present a Bayesian approach to prospective model comparison with parameter uncertainties considered. We tested nine geothermal stimulation case studies to comprehensively demonstrate that injection pressure is indeed the main physical predictor of induced seismicity relative to injection rate, and when combined with the latter as predictors, can give the best-performing model and robustly enhance real-time probabilistic forecasting of induced seismicity. We also discussed the implications of our results for seismic risk management and potential directions for further model improvement.

The behaviors of bubble migration and pressure build-up during a dynamic shut-in procedure in deep-water drilling

A dynamic shut-in procedure is commonly adopted after a kick incident in order to build up the wellbore pressure, obtain reservoir information, and thereby handle the gas kick. In deep-water scenarios, the hydrate growth behaviors have a significant effect on gas migration and interphase mass transfer, which has not been quantitatively analyzed during the well shut-in process. In this study, a comprehensive mechanistic model of wellbore dynamics is developed considering gas migration and phase transitions. The simulation results show that the wellbore pressure field can be built up in different trends during different well shut-in periods, governed by gas seepage from the reservoir and gas migration along the wellbore, respectively. Masking the migration of free gas, the phase transition phenomena have a significant influence on the wellbore dynamics and bottomhole pressure. This work adds further insights into quantitatively characterizing the hydrate growth behaviors and interphase mass transfer rules of gas bubbles during a dynamic well shut-in procedure.

Early monitoring of gas kick in deepwater drilling based on ensemble learning method: A case study at South China Sea

Gas kick monitoring is of great significance for prevention of blow-out accidents, especially in deep drilling and deep-water drilling. In this study, a machine learning (ML) model for early-monitoring of gas kick is developed using the ensemble learning algorithms based on 7363 lines of drilling logging data at South China Sea. The selected input parameters based on mechanism analysis of gas kick are six fast engineering parameters, including hook load (WHO), weight on bit (WOB), torque (TOR), flow rate (FLW), rate of penetration (ROP) and stand-pipe pressure (SPP), and two slow mud property parameters, i.e. electrical conductivity (CON) and mud outlet density (DEN). The model is constructed using RUSboosted, Subspace-KNN and Bagged Trees algorithms, and is compared with the neural network algorithm. We propose a comprehensive error to quantitatively evaluate the performance of the gas kick monitoring models. The models for early-monitoring of gas kick are applied for a single well and multiple wells, respectively. The results indicate that: (i) The optimal combination of input parameters is made up of six fast engineering parameters and two slow mud parameters. When there is a higher requirement on timeliness, only use of the six fast engineering parameters is also acceptable. (ii) The ensemble learning models work well when the input data expand from single well to multiple wells in the same block. For most cases, the prediction error of the optimal model is below 10%. The RUSboosted algorithm performed best in most data sets. (iii) Gas kick identification from lots of drilling logging records is mathematically a small-sample problem. The output labelling of a potential gas kick should be based on the field practical requirement. The recommended positive length of continuous-point labelling method is 5 m for the studied area, which can effectively reduce the average error from 8.02% to 5.48%.

Fiber-Optic DAS and DTS for monitoring riser gas migration

Free gas in a marine drilling riser presents a hazardous situation as the gas can quickly expand to produce dangerous gas volumes at the surface. However, the conventional gas kick detection methods, that rely on surface measurements and data from point sensors or gauges, are often inadequate to predict the dynamic behavior of a given amount of gas entering the riser. This study presents comprehensive results from well-scale experiments that demonstrate novel insights into the real-time gas rise behavior across a 5163-ft-deep wellbore using distributed fiber-optic sensors. The experimental well simulates an offshore marine riser-like scenario with its larger than average annular space and fluid circulation capability at high pressures and rates. Thus, the experimental and numerical model results in this study provide useful insights on gas rise dynamics in a large annular space along long intervals, which are relevant for studying gas in marine risers.Distributed acoustic sensor (DAS) and distributed temperature sensor (DTS) results from eight sets of well-scale tests are presented to investigate the effect of gas kick volumes (from 2 bbl to 15 bbl), circulation rates (from 0 to 200 GPM), and gas injection methods (through tubing or a ½-in. capillary injection line), on gas rise dynamics in the wellbore. Since slow-moving gas bubbles create small vibration and temperature effects, a variety of time- and frequency-domain signal processing techniques are developed to analyze the Fiber data were processed using frequency band energy (FBE), time-frequency scalograms, energy spectrums, frequency-wavenumber (FK) transform, and signal-to-noise ratio analysis. Gas velocities measured independently from DAS and DTS were validated using a numerical model, as well as with downhole pressure gauge data analysis, demonstrating good agreement for all eight trials. The numerical model presented in this study was validated with the downhole gauges and presents many useful insights for gas-in-riser conditions, such as gas arrival at the surface and rate of pressure build-up in closed wells.

Wellbore multiphase flow behaviors of gas kick in deep water horizontal drilling

During the deepwater drilling, the complicated gas-liquid-solid multiphase flow will occur if the formation gas enters and migrates in the wellbore. Through understanding of the wellbore flow behaviors is of great importance for the blowout prevention and well control. Considering the dynamic mass and heat transfer process in wellbore caused by alternating ambient temperature field, a multiphase flow model of multicomponent fluid in wellbore is deduced and developed, including the continuity equation, momentum conservation equation and energy conservation equation. Furthermore, the corresponding initial and boundary conditions are proposed for different working conditions in deepwater drilling, and an efficient numerical solution method is established, including dynamic mesh generation method and discrete solution method of partial differential equations. Applied in a deep-water kicking well, the proposed model is used to analyze the multiphase flow rules in the wellbore. The results show that in the process of annular fluid returning from the bottomhole, the pressure generally decreases linearly, while the temperature change is nonlinear. The temperature first rises and then falls at the formation section, and first falls and then rises at the seawater section. Furthermore, the pit gain increases approximately in a quadratic polynomial relationship, caused by the rise and expansion of gas in the wellbore, and the pressure drop and gas influx rate increase at the bottomhole. In the process of kick evolution, the standpipe pressure and bottomhole pressure gradually decrease, which can be an important sign for kick detection.

Combining Knowledge and a Data Driven Method for Identifying the Gas Kick Type in a Fractured Formation

The main forms of gas kicks into the wellbore during drilling in fractured carbonate reservoirs are underbalanced pressure and gravity displacement. These two forms of gas kicks have different mechanisms of gas entry into the wellbore and different well control measures, which require the timely identification of the type of gas kick when it occurs. A two-phase flow model with a wellbore-formation coupling was developed, based on the gas kick rate models. The variation characteristics of the bottomhole gas influx rate, the wellbore free gas, the bottomhole pressure, the bottomhole pressure change rate, the pit gain and the outlet flow rate during an underbalanced pressure gas kick and a gravity displacement gas kick, were compared and analyzed. Combining the dynamic time warping (DTW) and the wellbore-formation, coupled with a two-phase flow model, an identification method of the gas kick type, based on the DTW was proposed. Following the detection of the gas kick, the identification is performed by calculating the DTW distance between the surface parameter time series, obtained from the two-phase flow simulation and the surface parameter time series, measured in real time. The field example results show that the method can identify the type of gas kick, based on the real-time surface measurement parameters and provide a basis for taking targeted well control measures.

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.

Warning Signs of High-Pressure Formations of Abnormal Contour Pressures When Drilling for Oil and Natural Gas

When drilling to obtain hydrocarbons (oil and natural gas), we cannot underestimate the anomalously high pressures in the deposit layers, as these pressures can cause an uncontrollable eruption. Therefore, it is important to look for signs of anomalous high contour pressures over time, which, according to a detailed analysis, could be used to predict and quantify high formation pressures. These arise under conditions of intense vertical migration of formation fluids, where the liquids in the well have to carry part of the weight of overlying rocks and are often also related to tectonic activity. The main aim of the present study was to detect the emergence of a gas kick, which, as a result of an improper technological procedure, can cause an uncontrollable eruption, which can lead to a total accident of the well. In this article, we describe the use of modern drilling technology and sophisticated software that displays the current status inside the well. These can reveal impending pressure anomalies that can cause complications in managing the gas kick in oil and natural gas drilling. We analysed the most appropriate procedure for well control in a hydrocarbon well using the “driller’s method” and the “wait and weight method”. On the basis of theoretical background, we verified the correctness of the procedure for well control and compared it with the reaction to gas kick from a well drilled in Hungary. In the article, we highlight mistakes, as well as the particular importance of properly managing gas kick and its early prediction. Proper management of gas kick and its early prediction highlight the particular importance of implementing safe and effective procedures in well drilling.

Wellbore drift flow relation suitable for full flow pattern domain and full dip range

Aiming at the simulation of multi-phase flow in the wellbore during the processes of gas kick and well killing of complex-structure wells (e.g., directional wells, extended reach wells, etc.), a database including 3561 groups of experimental data from 32 different data sources is established. Considering the effects of fluid viscosity, pipe size, interfacial tension, fluid density, pipe inclination and other factors on multi-phase flow parameters, a new gas-liquid two-phase drift flow relation suitable for the full flow pattern and full dip range is established. The distribution coefficient and gas drift velocity models with a pipe inclination range of −90°–90° are established by means of theoretical analysis and data-driven. Compared with three existing models, the proposed models have the highest prediction accuracy and most stable performance. Using a well killing case with the backpressure method in the field, the applicability of the proposed model under the flow conditions with a pipe inclination range of −90°–80° is verified. The errors of the calculated shut in casing pressure, initial back casing pressure and casing pressure when adjusting the displacement are 2.58%, 3.43%, 5.35%, respectively. The calculated results of the model are in good agreement with the field backpressure data.

Management Of Shallow Gas Kick At Syh-05 Well In West Java Area

SYH-05 Well Drilling Operation West Java Area, was planned to be drilled with a final depth of 1694.65 mMD / 1500 mbpl by directional well drilling. Drilling hazards on the 17½” trajectory were shallow gas, gumbo, and bit balling. Furthermore, on this trajectory, shallow gas handling and optimization of drilling were going to be executed through shallow gas kick countermeasures in the SYH-05 Well. The high gas readings from the SYH-03 Well and the SYH-04 Well are 867 units and 1275 units, respectively, at a depth of 500-520 mMD intervals.After carrying out mitigation for shallow gas mitigation, the SYH-05 Well would use a higher Mud Weight than the reference well in this study starting with MW 1.12 SG while the reference well started with MW 1.08 SG, and the use of Annular – Single Ram 21-1/ 4” 2K with 10” Ball Valve as Diverter System. Moreover, to overcome the Kick Volume which was larger than the 17-1/2” hole, a 12-1/4” Pilot Hole would be installed. Prepare High Density Mud as a Contingency Plan and 4 Mud Pumps to anticipate the implementation of High Flow Rate Dynamic Kill. In the Cementing Design process, Gas Tight Slurry Cement would be applied.Based on the Casing Setting Depth analysis in the SYH-05 well drilling operation, there were 4 trajectories, namely: Conductor Casing 20”, 0-80m; Surface Casing 13-3/8”, 80-663.69m; Production Case 9-5/8”, 663.69-1060m; and Production Liner 7”, 1060.50-1694.65m. The implementation of Well Control was aimed to tackle the shallow gas kick was successfully executed in less than 1 hour without incident or accident. Work on the 17-1/2” trajectory which was a shallow gas zone could be done with the planned timetable.Keywords: Drilling hazard, Shallow gas kick, Optimization, Countermeasures

Preventing sour gas kicks during workover of natural gas wells from deep carbonate reservoirs with anti‐hydrogen sulfide fuzzy‐ball kill fluid

AbstractWorkover of natural gas wells in deep carbonate gas reservoirs (DCRs) is facing multiple challenges such as fluid leakage, high temperature, and hydrogen sulfide (H2S) gas kick. Hence, well‐killing fluids with satisfactory plugging ability, high‐temperature tolerance, and anti‐H2S ability are necessary. In this study, we developed a multifunctional anti‐hydrogen sulfide fuzzy‐ball kill fluid (AFKF) for preventing sour gas kicks in DCRs. The performance of the AFKF was optimized and analyzed via experiments and verified through a case study application. The results showed that the fuzzy‐ball structures in the AFKFs demonstrated good stability under extreme H2S aging. The rate of change of certain critical rheological parameters such as apparent viscosity, dynamic plastic ratio, and density of AFKFs before and after hot rolling were no more than 5%. After plugging the fractures with the AFKFs at temperatures between 110°C and 150°C, the inlet driving pressure of the fractures increased from 20.73°C to 21.07 MPa, and no fluid loss was observed at the core outlet after a secondary displacement of formation water. The permeability recovery rate was greater than 90%. Application of AFKF in well DW‐2 showed that the shut‐in pressure rose to 24.6 MPa with no trace of H2S gas at the wellhead after 4 days. The investigation of the H2S mitigation mechanisms revealed that the plugging of the seepage channels by AFKFs forms interconnected bonds that improve the mechanical properties of the reservoir. Additionally, AFKFs absorb H2S gases by protonation and dissociation reactions which convert the hazardous gas into an aqueous solution of sulfide ions (S2−). The proposed AFKF has proven to be effective means of mitigating H2S in DCRs, and minimize the negative impacts of environmental polution, health risks, and equipment corrosion.

Inversion-based model for quantitative interpretation by a dual-measurement points in managed pressure drilling

Deep wells control safety problems have always been the focus of attention due to the influence of complicated geological conditions, such as high-temperature and high-pressure (HTHP). Considering the mathematical model is only approximation of reality, thus the continuous transmission of real-time measurements is more popular, which can be used to identify the undetermined downhole parameters and improve accuracy of the model predictions. In the current study, we use two pressure while drilling tools to monitor downhole parameters in real time. Firstly, combined with the unscented-Kalman-filter (UKF) algorithm, a well hydraulics forward model with density factor and friction factor based managed-pressure-drilling (MPD) system is developed to quantitatively analyze the actual transient annular pressure. Secondly, a new multi-phase flow inversion model is established by determining the inversion parameters as gas kick rate and the position of the gas kick, which is used to track the values of pressure and outlet flow rate in real-time. The results of the case indicate that the inversion accuracy of the inversion parameters increases with the distance between dual-measurement points, and the reasonable value is selected as 30 m. Additionally, the proposed model is successfully validated using synthetic data and experimental data, where the maximum errors in predicting the position of the gas kick are only 3.1% and 5.3% when tuning the model stably tends towards the true value, respectively. The proposed model achieves accurate quantitative interpretation and analysis of downhole gas kick conditions, further clarifies the previously unknown key parameters of downhole gas kick, and has important significance for the realization of safe and efficient drilling.

Experimental Investigation on the Effect of Methane Solubility in Oil-Based Mud Under Downhole Conditions

Accurate prediction of CH4 solubility in oil-based mud is significant for evaluating gas kick severity and implementing proper well control. The main factors affecting gas solubility in oil-based drilling fluid are base oil content, pressure, temperature, drilling fluid viscosity, and the components in natural gas. This work tests the complete series of solubility of high-purity CH4 in oil-based mud simulating downhole conditions on a 5,000-m-deep well relative to temperature, pressure, viscosity, and base oil content with temperature ranging from 40°C to 140°C and pressure ranging from 2 to 56 MPa using a PVT autoclave. Then, the effects of temperature, pressure, base oil content, and drilling fluid viscosity on the test target are analyzed using multiple experimental data processing methods. It is found that the variation of methane solubility with pressure and temperature are almost linearly under interested ranges. The effects of pressure (0.205 to ~0.294%/MPa) are much higher than that of temperature (–0.008 to –0.011%/°C) in oil-based drilling mud; the solubility of methane decreases as viscosity increases. Models for predicting methane solubility have been developed using screening procedures and statistics regression, which can be integrated into gas-liquid flow models to investigate flow behavior while gas kicking.

Evolution of gas kick and overflow in wellbore and formation pressure inversion method under the condition of failure in well shut-in during a blowout

With ongoing development of oil exploration and techniques, there is a significant need for improved well control strategies and formation pressure prediction methods. In this paper, a gas-liquid transient drift flow model was established according to the gas-liquid two-phase flow characteristics during the gas kick. A Roe scheme was used for numerical calculation based on the finite volume method. The changes of bottom-hole pressure, casing pressure, the development law of cross-sectional gas holdup, and gas velocity, along with the vertical well depth, were analyzed through simulation examples. The time-series characteristics of mud pit gain were obtained by adjusting the formation parameter. The complex nonlinear mapping relationship between the formation parameters and the mud pit gain was established. The long short-term memory network (LSTM) of deep learning was used to obtain a formation pressure inversion when the blowout is out of control and the well cannot be shut-in. Experimental data from a well were used to verify the gas-liquid two-phase transient drift flow model based on the finite volume method, demonstrating that this method is reliable, with greatly improved prediction accuracy. This approach provides theoretical support for the early monitoring of gas kick during drilling, and for well-killing design and construction after uncontrolled blowout.