Annular Fluid Research Articles

Design and field-scale demonstration of the buoyant-kill process for restoring integrity of wells with sustained casing pressure

Sustained Casing Pressure (SCP) is the persistent casinghead pressure resulting from the well’s annular integrity loss and migration of gas above the leaking cement sheath. Downhole—intervention methods for SCP removal employ workover rigs to access and plug off the leaking annulus at depth from within the well. The inexpensive rig-less method of Buoyant Kill involves surface injection of immiscible heavy fluid at the casinghead into the well’s annulus to replace the annular fluid column above the gas-leaking cement and stop gas migration. Laboratory and pilot-size testing have shown feasibility of the method. Presented here, is a field-scale demonstration experiment conducted in a pressurized 2750-foot well with water displaced by an immiscible brominated organic fluid over 20-h long operation. Discussed is experimental design supported by fluid selection study, benchtop and pilot tests, and fluid transport model. Also analyzed is the process performance and operational problems. The results confirm feasibility of the Buoyant Kill technique for SCP removal. The overall change of the wellhead and downhole pressures follows the expected patterns indicating partial removal of the simulated SCP. The removal is incomplete due to pumping pressure pulses and wellhead pressure variations resulting in some emulsification of the two fluids and partial loss of the injection fluid into the overflow. The results show that wellhead pressure control and injection pump operation are critical for successful SCP removal using the Buoyant Kill technique.

A New Model of Bubble Migration Velocity in Deep Water Wellbore Considering Hydrate Phase Transition

Mass transfer and phase transition have an important effect on the velocity of bubble migration in deepwater wellbores, and accurate prediction of bubble migration velocity is crucial for calculating the safe shut-in period of deepwater oil and gas wells. Therefore, the effect of bubble dissolution mass transfer and hydrate phase transition on bubble migration behavior in the deepwater environment have attracted extensive attention from researchers in the fields of energy, marine chemistry, and marine engineering safety. In this work, a new model of bubble migration velocity in deepwater is developed, which considers the effect of hydrate phase transition and gas-water bidirectional cross-shell mass transfer during bubble migration. Based on the observation data of bubble migration in deepwater, the reliability of the model in predicting bubble migration velocity is verified. Then, the model is used to calculate and analyze the bubble migration velocity and bubble migration cycle under different initial bubble size, different annular fluid viscosity, and density. The results show that the initial size of bubble and the viscosity of annulus fluid are the main factors affecting the migration velocity of the bubble, but the density of annulus fluid has little effect on the migration velocity of the hydrated bubble and clean bubble. In addition, the migration velocity of the clean bubble gradually increases during the migration process from the bottom to the wellhead, while the migration velocity of the hydrated bubble is divided into a gradually decreasing stage and a slowly increasing stage. The gas consumption and the thickening of hydrate shell in the gradually decreasing stage play a dominant role, and the increase of bubble volume caused by the decrease of pressure in the slowly increasing stage is the most important factor. The formation of the hydrated bubble can significantly reduce the migration velocity of the bubble and effectively prolong the safe shut-in period. This study provides a reference for quantitative description and characterization of complex bubble migration behavior with phase change and mass transfer in deepwater environment.

Numerical study of the steady core-annular flow in a focusing geometry in the presence of soluble surfactants

The steady state core annular flow of two immiscible fluids in the presence of soluble surfactants is investigated numerically in an axisymmetric tubular or flow focusing geometry. The two immiscible fluids form an interface onto which surfactants can be adsorbed/desorbed from the annular fluid where they are dissolved. The finite element method is employed to discretize the governing equations using the spine method to create the computational mesh, follow the shape of the interface and the axisymmetric wall and capture the flow domain. An unknown pressure distribution is imposed along the interface that quantifies the pressure discontinuity, while allowing the bulk pressure to remain continuous in each phase. GMRES is employed to accommodate the nearly singular nature of the jacobian matrix. The bulk surfactant concentration varies only inside a thin boundary layer of thickness δ∼Pe−1, which justifies omission of the advection-diffusion equation in the annulus bulk. Simulations reveal that the onset of Marangoni stresses tends to decelerate the velocity at the interface which is seen to translate towards the wall/axis of symmetry when the more viscous fluid is the inner/outer fluid, respectively. Finally, simulations in flow-focusing nozzles capture the development of spatially growing instabilities in the downstream region of the interface, with wavelength on the order of the nozzle radius, especially when the outer fluid is more viscous or when the surfactant concentration increases. Raising the volumetric flow rate in the annular region suppresses growth of waves due to interfacial friction. Spatial stability analysis verifies downstream growth of waves and recovers the relevant wavelength. Possible repercussions on the onset of jetting instabilities in devices with liquid focusing are discussed.

Secondary flow of an elasto-visco-plastic fluid in an eccentric annulus

In this paper we study the flow an elasto-visco-plastic fluid whose deviatoric stress is made up by a “seemingly” visco-plastic part (regularized Bingham fluid) and a viscoelastic part (Rivlin–Ericksen fluid) in a “slightly” eccentric annulus. The flow is driven by an applied horizontal pressure gradient and by the motion of the inner cylinder. Using the eccentricity as perturbation parameter we show that secondary flows appear at the first order approximation. We investigate the various flow patterns depending on the different non-dimensional groups appearing in the governing equations. In particular we observe the occurrence of rotating and counter-rotating vortices depending on the material and geometrical parameters of the system.

Natural convection of power-law fluid in a horizontal annulus between outer cylinder and inner flat tube

Natural convection of power-law fluid in a horizontal annulus between outer cylinder and inner flat tube

Simulation study on cuttings transport of the backreaming operation for long horizontal section wells

The backreaming operation plays a significant role in safe drilling for horizontal wellbores, while it may cause severe stuck pipe accidents. To lower the risk of the stuck pipe in backreaming operations, the mechanism of cuttings transport needs to be carefully investigated. In this research, a transient cuttings transport with multiple flow patterns model is developed to predict the evolution of cuttings transported in the annulus while backreaming. The established model can provide predictions of the distribution of cuttings bed along the wellbore considering the bulldozer effect caused by large-size drilling tools (LSDTs). The sensitivity analyses of the size of LSDTs, and backreaming operating parameters are conducted in Section 4. And a new theory is proposed to explain the mechanism of cuttings transport in the backreaming operation, in which both the bit and LSDTs have the “cleaning effect” and “plugging effect”. The results demonstrate that the cuttings bed in annuli is in a state of dynamic equilibrium, but the overall trend and the distribution pattern are obvious. First, larger diameters and longer drilling tools could lead to a higher risk of the stuck pipe. Second, we find that it is not the case that the higher flow rate is always better for hole cleaning, so three flow-rate intervals are discussed separately under the given conditions. When the “dangerous flow rate” (<33 L/s in Case 4) is employed, the cuttings bed completely blocks the borehole near the step surface and causes a stuck pipe directly. If the flow rate increases to the “low flow rate” interval (33–35 L/s in Case 4), a smaller flow rate instead facilitates borehole cleaning. If the flow rate is large enough to be in the “high flow rate” interval (>35 L/s in Case 4), the higher the flow rate, the better the cleaning effect of cuttings beds. Third, an interval of tripping velocity called “dangerous velocity” is proposed, in which the cuttings bed accumulation near the LSDTs is more serious than those of other tripping velocities. As long as the applied tripping velocity is not within the “dangerous velocity” (0.4–0.5 m/s in Case 5) interval in the backreaming operation, the risk of the stuck pipe can be controlled validly. Finally, through the factors analyses of the annular geometry, particle properties, and fluid properties in Section 5, it can be found that the “low flow rate”, “high flow rate” and “dangers flow rate” tend to decrease and the “dangerous velocity” tends to increase with the conditions more favorable for hole cleaning. This study has some guiding significance for risk prediction and parameter setting of the backreaming operation.

Monitoring of the energy state of oil fields using permanent well monitoring systems

The paper shows the necessity and specific features of well tests for controlling the development of oil fields. The approaches to monitoring the operation of wells using continuous measurement of parameters by pressure sensors of telemetry systems and continuous measurements of annular pressure and fluid level by stationary level gauges are considered. The analysis showed that the determination of reservoir pressures by measuring the static level has a degree of reliability comparable to the reliability of buildup or drawdown well test methods. The application criteria, advantages and limitations of the proposed and implemented approaches are shown. An economic assessment of the proposed approaches is carried out.

Sour-Rated 10,000-psi System High-Temperature Gas Development Wells: Sustaining the Malaysian National Gas Supply Through a Journey of Optimization in North Malay Basin

Summary High temperature (HT), high carbon dioxide (CO2) coupled with hydrogen sulfide (H2S) contents, and rapid pore pressure fracture gradient (PPFG) pressure ramp increase in gas development wells can lead to significant capital expenditures for operators. Such wells typically need high corrosion resistance alloy material with at least a 10,000-psi (10-ksi)-rated system to complete. The deep reservoirs of the North Malay Basin, offshore peninsular Malaysia, also fall into the described category. In this paper, we aim to share the optimization journey, applications, and learnings of the company’s HT sour-rated 10-ksi gas development wells through several phases, besides fulfilling the gas delivery need for the country. In addition, we identify engineering and operational optimizations to reduce the well’s time and cost while upholding the safety of the crew as a top priority. The sour-rated HT gas development campaign for the company began in the year 2017, followed by a second campaign in the year 2018. Our focus centers on the third campaign, which concluded in the year 2022. A total of four, three, and four wells were drilled and completed in the first, second, and third campaigns respectively. The company’s wells engineering team applied Lean methodologies that covered the entire Plan-Do-Check-Adjust cycle to achieve optimization. Using well data, learning from experiences, working together, maintaining consistency, and pursuing ongoing enhancements are the main factors that ensure positive optimization outcomes. Fit-for-purpose drilling and completions equipment design and application, rig offline capabilities planning, wellhead dummy hanger plug design for offline cementing, intervention-less production packer setting device, offline annulus nitrogen cushion fluids displacement, and other applications will be explained in the paper. In this paper, we describe the operational challenges faced and outline the applied optimizations that led to significant improvements in the well performance compared with targets and previous campaigns. The optimization efforts by the wells team extended from the engineering phase to the execution stage, including the use of in-house digital capabilities to monitor well performance, in alignment with industry practice. The recent campaign post-optimization concluded with no safety incidents, average per well more than 48 days ahead with 39% lower cost than previous campaigns, average of 5.6% overall well nonproductive time (NPT), and achieved first gas to meet the country’s power generation demand. Furthermore, the motivating optimization results also coupled with 25% more production results compared with the prognosed. The positive results of this optimization journey were significantly influenced by transparent, collaborative, and proactive communication across different departments.

Cfd Analysis in Coaxial Injector of a Cryogenic Rocket Engine And Evaluation of Atomisation Characteristics Using Simulant Fluids

A Study of atomisation and mixing of 2-phase propellants using simulant fluids injected from a coaxial injector of an operating cryogenic rocket engine is carried out and presented along with the CFD analysis of flow within it. The original injector jet (Jet 3) designed, modeled and analysed has swirl for LOX (water) alone with GH2 (air) having no swirl. Injector jet having inner casing and outer sleeve is modeled using I-DEAS software and analysed for inner core fluid domain (liquid) and annular fluid (air) domain. Results of flow analysis inside jet revealed asymmetric nature of air flow at exit due to the air fluid domain itself is not axisymmetry in the original jet. This non-axisymmetry of 2-phase fluids at the exit of injector jet will obviously affect the characteristics of atomisation and mixing of fluids. Data obtained from atomization experiments done on this jet using stimulant fluids (water in LOX side and air in GH2 side) such as particle distribution and Sauter Mean Diameter (SMD), fairly matches with the predictions made using CFX software and associated codes which enabled to evaluate the analysis software. Further, the air flow at exit has been made axisymmetric by modifying the air passage in the injector jet (Jet 3 Mod) and the effect of this modification on atomisation and mixing of 2-phase fluids is predicted using the CFX software. In combustion better efficiency with less instability is to be attained. For meeting both simultaneously articles size distribution after injection has to be neither very finer nor coarse. Comparison of predicted data on atomisation revealed that the modified Jet (Jet 3 Mod) is relatively better to give stable combustion with higher performance.

Research on the Stability of the Spacer Fluid Interface in Dual-Layer Pipe Dual-Gradient Drilling

Dual-layer pipe dual-gradient drilling technology is an emerging technology for solving the problem of the narrow safety density window in deepwater drilling. The unstable spacer fluid interface in this technology directly affects the dual-gradient pressure system in the annulus, causing changes in the drilling mud performance and affecting the control of bottom hole pressure and rock removal with drilling mud. Therefore, the key to the stable operation of dual-layer pipe dual-gradient drilling technology is to maintain the stability of the spacer fluid interface. Based on this, a seawater-spacer fluid-drilling mud annular flow model was established in this study, with a bottom hole pressure control step of 0.2 MPa, and the spacer fluid height after a single control was used as the evaluation index to study the influence of annular flow velocity, the spacer fluid properties, and the drill string rotation speed on the stability of the spacer fluid interface. The results show that in the determined conditions of the seawater and drilling mud system, the annular fluid flow rate and the physical parameters of the spacer fluid are the main factors affecting the stability of the spacer fluid interface. When the annular fluid flow rate increased within the range of 0.04~0.2 m/s, the liquidity index of the spacer fluid increased between 0.5 and 0.9, the consistency coefficient increased in the range of 0.6 to 1.4 Pa⋅sn, and the stability of the spacer fluid interface decreased. However, the stability of the spacer fluid interface increased with the increase in its density in the range of 1100~1500 kg/m3. The results obtained in this study can provide a reference for selecting the operating parameters to ensure the stable operation of dual-gradient pressure systems.

Flow modeling and in situ viscosity monitoring for a combined rotational and pressure-driven flow of a non-Newtonian fluid through a concentric annulus

Based on the energy dissipation rate, we proposed a systematic method for quantifying the effective viscosity, effective shear rate, and flow characteristics in a drilling flow of non-Newtonian fluids in a concentric annulus subjected to a combined pressure-driven and rotational flow. Two flow parameters, i.e., the energy dissipation rate coefficient and the effective shear rate coefficient, were introduced to quantify flow characteristics, such as the relationship between pressure drop, flow rate, torque, and rotational speed, which are nearly independent of rheological behaviors. In this work, we began with flow quantification of the individual flow problem in a concentric annulus, i.e., pressure-driven flow and rotational flow, and derived expressions of two flow parameters analytically in each case. Then, we established the flow quantification method for the combined pressure-driven and rotational flow. The proposed flow modeling scheme was derived analytically with a power-law fluid and was validated for various non-Newtonian fluids, such as Carreau and Herschel–Bulkley fluids, through extensive numerical simulations. The method can be employed for the in situ viscosity measurement of drilling muds in terms of shear rate, as well as for the estimation of torque, pressure drop, and power consumption. Maximum errors between theoretical prediction and numerical simulation results in estimating torque, pressure drop, and shear-dependent viscosity were found to be 5.5%, 7.3%, and 6%, respectively.

Development of annular pump to enhance drilling distance and cuttings return in horizontal directional drilling

In many shallow horizontal directional drilling (HDD) projects, the annulus fluid pressure soon reaches the blowout or frac-out pressure of the soil formation. The pressure at single-source pump therefore must be limited. This limits the maximum drilling distance (borehole length), maximum attainable rate of penetration (ROP), and maximum distance over which cuttings can be returned. A novel concept involving a series of annular pumps distributed along the borehole length to aid in generation of distributed annulus pressure boost and cuttings transport in HDD was conceived. The success of the above concept, designated as distributed pumping system (DPS), relies on the ability to design and power an annular pump that can fit in the constricted annulus geometry of HDD boreholes while satisfying the performance requirements. We present the laboratory-scale development of three annular pumps based on the turbomachinery design principle of axial blade propellers. The pump prototypes were 3D printed and tested in the laboratory test rig flow loop built to simulate the annular flow configuration of HDD boreholes. The annular pump was powered using the axial propeller turbine housed inside the hub of each annular pump. The turbine converts hydraulic energy from the inner flow (analogous to drilling fluid flow within drill rod) to power the integrated setup of the axial inner turbine and annular pump, in short, designated as integrated turbine-pump (ITP). Results from the tests on three preliminary prototypes of the annular pump using water as the medium in the test rig yielded a maximum pressure boost of 44 kPa–enough to space the annular pumps 80 m apart when designed for a typical annular pressure drop rate of 0.54 kPa/m. The performance index (i) of the ITP, defined as the ratio of pressure boost provided by the annular pump in the outer (annular) flow to the pressure drop created by an inner turbine in the inner flow, reached a maximum value of 0.6. The results from the study promise a technology that can enable long-distance HDD cuttings return without the risk of blowout or the need for an external power source.

A coupling prediction model of annular pressure build-up for deepwater oil and gas wells during transient-state testing

To accurately predict annular pressure build-up of deepwater high pressure-high temperature oil and gas wells during the transient-state testing, a coupling prediction model of trapped & untrapped annular pressure build-up is proposed. For the short-term process of gas well transient testing, a wellbore transient heat transfer model has been established. Then the improved coupling model of trapped & untrapped annular pressure build-up is established, which is not only novelly considering fluid thermodynamic properties (isobaric expansion coefficient and isothermal compression coefficient) under high pressure-high temperature conditions and annulus fluid mass changes of untrapped annulus, but also considering annulus volume changes. For precise coupling calculating the annular pressure build-up, the annulus is divided into infinitesimal grid cells along well depth. The impact of different considering factors, testing times, testing production rates, formation permeability and cement sheath sealing positions on the annular pressure build-up in the model is investigated. The results show that conventional models (high pressure-high temperature properties and mass changes of the fluid are not considered) will greatly overestimate the annular pressure build-up; as the testing time increases, the impact of untrapped annulus fluid mass changes on the annular pressure build-up will gradually take the dominant role; reasonably optimizing the setting of untrapped annulus open hole section in high permeability formations and increasing the distance between cement sheath and the upper casing shoe can effectively relieve the increasing annular pressure build-up. These findings can achieve accurate prediction of trapped and untrapped annular pressure build-up, and play an important role in guaranteeing the wellbore integrity and safety of deepwater oil and gas wells during transient-state testing.

Temperature distribution of shale oil wellbore considering oil-based mud and formation fluid displacement

Oil-based mud is widely used in shale oil well drilling because of its good stability and high temperature resistance at high temperature. However, during the drilling process of shale oil wells, fluid displacement between the annulus and the formation occurs. The existing temperature field model cannot predict the temperature distribution of the wellbore annulus under this condition. Based on the equations of heat conduction and conservation of energy, a new model of wellbore heat transfer in shale oil wells considering the displacement between downhole fluids is established in this paper. By comparing the temperature distribution of annular fluid under normal circulation, lost circulation and overflow, the accuracy of this model is confirmed. Taking the parameters of a shale oil well in a certain area as an example, the factors that affect the temperature of the annular fluid are analyzed and solved. Numerical analysis and simulation results show that the flow rate remains unchanged, and the annular temperature decreases by about 1.42 °C/L when the flow rate of the annulus increases. As the specific heat capacity of shale oil increases, the annular temperature increases by about 0.0012 °C/J/(kg·°C). In addition, when displacement between fluids occurs in the upper open-hole segment, there is an inflection point on the temperature distribution curve of the annular fluid, and the location of the inflection point is consistent with the location of the fluid displacement point. The results can provide a theoretical reference for drilling in complex formations with frequent formation-annulus fluid displacement, leakage and overflow.

Numerical study of steady and periodic mixed convection of Bingham fluid in a narrow annulus with the exact Bingham model

This article numerically investigates the mixed convection of Bingham fluid in a narrow annulus. The temperature of the inner fixed cylinder ( θ i ) is higher than that of the outer one ( θ o ), which rotates at a constant angular velocity. An OpenFOAM solver, icoFoam, which works based on the finite volume method and the PISO algorithm, is modified to perform the simulations. The modified solver can solve unsteady heat transfer problems for Bingham fluids without using regularization methods. After validating the solver, it solves the problem in different conditions to show the effect of relevant parameters, such as Reynolds number, Bingham number, and aspect ratio, on the flow field and thermal performance of the enclosure for constant amounts of Grashof and Prandtl numbers. The results are presented as streamlines and isotherms, the size and shape of the unyielded regions, the local and mean Nusselt number, and the torque coefficient. The results demonstrate that the flow is steady at Re = 10 for all Bingham numbers, and a decrease in the Reynolds number may result in an unsteady flow depending on the value of the Bingham number. The flow’s time history reveals that at a fixed Reynolds number, the flow shifts from periodic to steady-state by enhancing the Bingham number so that the flow becomes entirely steady for a given Bingham number. An interesting phenomenon is observed, the formation, movement, and disappearance of the plug zones (unyielded regions) for the periodic flow at Re = 1 and Bn = 5 .

Study on the Galvanic Corrosion between 13Cr Alloy Tubing and Downhole Tools of 9Cr and P110: Experimental Investigation and Numerical Simulation

The galvanic corrosion of oil and gas production string is related to wellbore integrity and production safety. In order to study the galvanic corrosion of an oil and gas well tubing assembly and maintain production safety, this paper studied the galvanic corrosion behavior between 13Cr alloy steel tubing and the downhole tools of 9Cr and P110 in formate annular fluid via experimental and numerical simulation methods. The chemical composition, HTHP corrosion tests and electrochemical measurement of the three materials were investigated to analyze the corrosion mechanism and electrochemical parameters. Then, a full-sized 3D galvanic corrosion model of 13Cr tubing and a 9Cr/P110 joint combination was established using COMSOL Multiphysics software based on the electrochemical test results. The mechanism and current variation law of the galvanic corrosion of different tubing materials are discussed and analyzed in the paper. The results revealed that the corrosion rates obtained based on the electrochemical test are as follows: P110 (0.072 mm/y) &gt; 9Cr (0.033 mm/y) &gt; 13Cr (0.0022 mm/y). The current densities of a combination of 13Cr tubing with a 9Cr joint and 13Cr tubing with a P110 joint vary dramatically: the current density of the 13Cr tubing–P110 joint reach 1.6 × 10−4 A/cm2, higher than the current density of the combination of 13Cr tubing and a 9Cr joint. The results of a 3D FEM analysis show that the 13Cr tube demonstrates obvious galvanic corrosion with 9Cr and P110 joints, which is consistent with the analysis results of the polarization curve. This study therefore explains the galvanic corrosion mechanism of different tubing materials and provides guidance for the safe use of tubing in the productive process.

Numerical Simulation on the Safety and Quality of Cementing by Using Pad Fluid in Horizontal Wells

The failure of wellbore sealing will cause leakage of greenhouse gases, such as carbon dioxide and methane, which will harm oil and gas recovery and environmental safety. Cementing is an important part of wellbore sealing. Only good cementing can keep the wellbore seal for a long time and improve the well life. In this study, we considered the construction of a horizontal shale oil well in eastern China as the background and analysed the rheological properties of the annulus fluid. We developed a displacement motion model and a calculation model for the annulus dynamic equivalent circulation density, and numerical simulations were used to study the impact of the dosage and injection sequence of the pad fluid on the displacement efficiency and annulus dynamic equivalent circulation density. The results show that when the pad fluid is composed completely of flushing fluid, the displacement performance is better than that of the spacer. By increasing the dosage of the flushing fluid from 0.3 times the annular volume to 1.0 times, the displacement efficiency can be increased by 3.3%, and the retention of the drilling fluid is also reduced by 3.6%. However, it can lead to a significant reduction in the annulus dynamic equivalent circulation density and increase in the risk of leakage. After adding the spacer, the structure of the flushing fluid–spacer provides the optimal injection sequence. Considering the application status in the field example well, it was shown that it can not only ensure the safety of cementing operations, but also improve the displacement efficiency. The results of this study have important theoretical significance and application value and can provide guidance for the optimisation design of the engineering scheme.

Flow Field and Pressure Loss Characteristics at Rotary Drillstring Joints

A thorough understanding and accurate calculation of the annulus pressure losses are paramount to drilling design and construction. However, due to the influence of the drillstring rotation and the abrupt dimensional variation at the joint, it is difficult to calculate the pressure loss by theoretical analysis in the annulus at the drillstring joints. Considering the geometric nonlinearity of drillstring joints and the unsteady flow of annular fluid caused by pipe rotation, based on the turbulence model k − ε , the flow field characteristics demonstrate the annulus pressure losses at the drillstring joint are studied by numerical simulation. Simulation results indicate that drillstring rotation speed, annular gap, and eccentricity greatly influence flow field and pressure losses at drillstring joints. The annular pressure loss would increase with the decrease of the annular gap and eccentricity but decrease with the increase of the drillstring rotation rate. The investigation method and results would help guide the design of drilling hydraulic parameters.

Effectiveness of Fiber Optic Distributed Acoustic Sensing (DAS) in Vertical Seismic Profiling (VSP) Field Survey

The evolution of fiber optic technology in the past few decades has led to significant advancements in various fields, including high-speed and long-distance communication, big data transport, optical imaging, and sensing. However, relatively few studies have examined the use of fiber optic sensors (FOSs) as point and distributed sensors in geophysics. Distributed Acoustic Sensing (DAS) is a widely used method for subsurface imaging and monitoring in wells, specifically in Vertical Seismic Profiling (VSP) surveys. This method allows for detailed analysis of subsurface structures and properties of reservoirs. Four different strategies for deploying FOS cables in DAS VSP are evaluated and compared: cementing behind casing, cable behind inflatable liner, strapping to production tubing, and wireline deployment. Cementing the fiber behind casing is considered the most effective method for coupling with the formation. However, the other methods also have their own advantages and limitations. The fiber cable behind inflatable liner, for example, allows for accessibility to the fiber without affecting the acoustic signal, while strapping the fiber to production tubing can still record DAS signals; tubing noise and signal attenuation from the annular fluid, however, can make it difficult to differentiate from the seismic signal. Nonetheless, this method has the benefit of being simpler to deploy and replace in case of failure. Wireline deployment can pick up some acoustic signals in regions where the cable touches the well wall, but in vertical sections where the cable is not in contact with the wall, the signal is attenuated. Results from pilot tests in a field in Canada are discussed and evaluated, and suggestions for improving the VSP signal are provided.

Magnetized flow of naturally convective viscous fluid in permeable rhombus-shaped annulus by executing FEM simulations

The present work is deliberated to investigate the flow and thermal behavior of viscous fluid flow in permeable rhombic-shaped enclosure. Annular region lying below inner and outer rhombuses is the area of concentration during this study. Magnetic field is employed in horizontal direction to envision aspects of Lorentz field. Governing equations are developed in dimensional form of partial differential setup. Numerical experiments via finite element approach are capitalized to find solution. Grid convergence test is executed to show domain distribution along with decision about mesh level at which computations are to conducted. Streamlines and isothermal maps are sketched to show comprehensive change in associated flow fields against governing parameters. Kinetic energy and average heat flux coefficient are evaluated in comparative manner for magnetic and hydrodynamic situations. Through attained outcomes, it is concluded that kinetic energy and heat flux coefficient enhances reduction against Hartmann number.