Wellbore Fluid Research Articles

Computing optimum drilling fluid density based on restraining displacement of wellbore wall

It is vital to design an optimum drilling fluid density for retaining the stability of wellbore wall in drilling engineering. Under estimated drilling fluid density will induce shear failure of wellbore wall. Conversely, wellbore wall will occur tensile failure. Drilling engineers have been looking for an optimum drilling fluid density for a long time. A new method to compute the optimum drilling fluid density was established in this study. Wellbore wall occurs displacement in the process of forming wellbore. The displacement of wellbore wall causes wellbore collapse or fracture. By designing a drilling fluid density to prevent the displacement of wellbore wall from happening, the collapse or fracture of wellbore can be decreased or avoided. Surrounding rocks of wellbore are subject to four forces, overburden pressure, maximum horizontal principal stress, minimum horizontal principal stress and hydrostatic wellbore fluid column, respectively. Mathematical expressions of radial displacement of surrounding rocks of wellbore and drilling fluid pressure were derived through elasticity theory. The latter expression can be used to compute the optimum drilling fluid density. Basic parameters, Young's modulus, Poisson's ratio, overburden pressure, maximum horizontal principal stress, minimum horizontal principal stress, in the expression can be obtained by utilizing logging information. In this work, the new method were used to compute the optimum drilling fluid density of three wells extracted randomly in Tarim Oilfield. Results show that the drilling fluid density values obtained through this method and actual drilling fluid density values in well site have a good fit.

Sensor Array Enables Accurate Profiling of Produced Fluids During Drillstem Tests

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 29749, “Determining Produced-Fluid Properties for Accurate Production Profiling During a Drillstem Test Using Thermal-Imaging Technology,” by David Lavery and David Fyfe, Metrol, and Abu Rashid Hasan, SPE, Texas A&M University, prepared for the 2019 Offshore Technology Conference Brasil, Rio de Janeiro, 29–31 October. Copyright 2019 Offshore Technology Conference. Reproduced by permission. This paper describes the use of a downhole temperature-sensor array during a commingled drillstem test (DST) to determine the density of produced fluids accurately. In a typical DST that uses only downhole pressure gauges, any fluid contacts between the pressure gauges would be missed and the produced-fluid density calculated would be erroneous. The complete paper demonstrates the importance of taking fluid properties into account when determining the zonal flow-rate contributions using the mass-enthalpy method. Introduction Downhole temperature-sensor-array data provide accurate fluid contact depths during buildup periods of the DST that typically cannot be observed in pressure gradients. Determination of these fluid contacts permits the calculation of individual produced-fluid densities. In a case study described in the complete paper, the deepest perforated zone produced a fluid with a higher density than that seen in shallower perforated intervals. The higher density of the produced brine caused the wellbore fluids to slug during the flow periods with a measurable response in pressure and temperature data. If this difference in the fluid properties is not taken into account, zonal-allocation flow rate will be in error because it relies on density and specific heat capacity. Qualitative assessment of the temperature-array data identified producing zones and clearly highlighted different fluid interfaces in detail that would remain hidden if the pressure gauges were relied upon solely. High-Resolution Temperature Measurement During DST Operations The deployment of the downhole temperature-sensor array during DSTs provides an in-depth look into reservoir characteristics that go beyond traditional downhole pressure-gauge measurements. The temperature sensors, contained within steel tubing and clamped to the outside of the tubing-conveyed perforating guns, cover the three perforated intervals in this case study. Two temperature sensor arrays were run, each with a sensor spacing of 0.6 m and offset with an effective sensor spacing of 0.3 m. Throughout the DST, the readings from the temperature sensor arrays were recorded on downhole memory devices at 1-minute intervals. The temperature measurement covered the entire perforated interval. High-resolution pressure gauges are placed above and below the perforated interval and above and below the tester valve. Using an acoustic communication system, real-time temperature and pressure data were available during the DST so that observations across the entire test could be made. Zonal Allocation of Produced Reservoir Fluids From Mass-Enthalpy Balance The mass-enthalpy method of calculating zonal contributions relies on intervals higher in the wellbore producing at a lower temperature than deeper producing intervals. The higher- temperature contributions from the deepest producing intervals will flow up the wellbore while losing some heat to the colder wellbore. The rate of cooling is dependent on the flow velocity. The shallower producing intervals contribute at a lower temperature than the mixture and will cool down the mixture. This method is detailed in the complete paper.

Analysis of the influence of ultrahigh pressure on wellbore Fluid properties——Take Well ST1 in north Sichuan as an example

According to the research on wellbore pressure temperature prediction of ultra-high pressure gas Wells, the influence of ultra-high pressure on wellbore fluid physical property parameters cannot be ignored, the component model is adopted to calculate wellbore fluid PVT physical property, and the multi-phase flow model is modified to accurately predict wellbore pressure temperature distribution. For the prediction of gas deviation factor of well flow and gas viscosity of well flow, the component model has a high precision. By comparing with the prediction results of 8 black oil model methods, the pressure has a great influence on the black oil model. When the pressure is equal to 100MPa, the deviation value between the predicted results of Gopal method and Dranchuk-Abu-Kassem method and the component model is greater than 0.1, which can no longer guarantee the accuracy of gas deviation factor and gas viscosity prediction. Therefore, it is recommended to use the component model to predict the deviation factor and gas viscosity of gas well flow.

Experimental study and CFD investigation of environment friendly drilling fluid

Environment-friendly drilling fluids have been developed recently, which protect the environment and satisfy needs of drilling engineering. In this study, to investigate the advantage of using environment-friendly drilling fluid, four (three vegetable and one diesel) oil-based fluids were prepared and their rheological properties were compared. Results showed that all fluids follow non-Newtonian Herschel-Bulkley model with high accuracy, and increasing of temperature results reduction of the fluid's apparent viscosity. Then, in order to study the cutting carrying capacity of the prepared drilling fluids in wellbore, a 3D form of steady-state computational fluid dynamics (CFD) model is used to simulate the flow in different conditions. The CFD results indicated that the vegetable oil muds represent better cutting transportation, especially in lower flow rates. For the fluid velocity of 0.75 m/s by increasing temperature from 320 to 363 K in constant pressure, the cutting transportation has been decreased by 4.21% and 3.07% for diesel and vegetable muds respectively. [Received: April 19, 2018; Accepted: May 10, 2019]

Experimental study and CFD investigation of environment friendly drilling fluid

Environment-friendly drilling fluids have been developed recently, which protect the environment and satisfy needs of drilling engineering. In this study, to investigate the advantage of using environment-friendly drilling fluid, four (three vegetable and one diesel) oil-based fluids were prepared and their rheological properties were compared. Results showed that all fluids follow non-Newtonian Herschel-Bulkley model with high accuracy, and increasing of temperature results reduction of the fluid's apparent viscosity. Then, in order to study the cutting carrying capacity of the prepared drilling fluids in wellbore, a 3D form of steady-state computational fluid dynamics (CFD) model is used to simulate the flow in different conditions. The CFD results indicated that the vegetable oil muds represent better cutting transportation, especially in lower flow rates. For the fluid velocity of 0.75 m/s by increasing temperature from 320 to 363 K in constant pressure, the cutting transportation has been decreased by 4.21% and 3.07% for diesel and vegetable muds respectively. [Received: April 19, 2018; Accepted: May 10, 2019]

Analysis of the difference between the test and production in Well Z202-H1

In recent years, shale gas in the Upper Ordovician Wufeng Formation and lower Silurian Longmaxi Formation is gradually developing into deep strata in Sichuan Basin. Well 202-H1 is a evaluation well deployed to evaluate the productivity of horizontal Wells in longmaxi Formation and Wufeng Formation in The West Chongqing block. The well type is horizontal well. The main reasons for the poor production effect of Well Z202-H1 are as follows: Reservoir pores are not developed; continuous thickness of thin reservoir; insufficient fracturing treatment; low flowback rate, large water production and wellbore fluid accumulation. This article not only obtained the reasons for the difference between the test and production of well Z202-H1, but also provided a new research idea for the test and production tracking analysis of deep shale gas static in The Western Chongqing block.

Numerical transient and steady state analytical modeling of the wellbore temperature during drilling fluid circulation

In this paper, a transient model that describes the heat transfer processes in the wellbore during circulation is presented. A simulation of the transient effect on these heat transfer processes was achieved by using a numerical approach to solve the thermal balance equations that describe the heat flow in that system. The present model can be applied for both laminar and turbulent flow regimes through the convective heat transfer coefficient (CHTC). The run time of the present model is relatively short, hence it can be applied for real-time simulation applications. This was achieved by simplifying the model and reducing the calculation complexity. Moreover, the present model has gone through different validation processes. First, the present model is reduced to a steady state condition and solved analytically. This solution was used as a reference to verify the results of the numerical model. Additionally, a grid sensitivity analysis was performed. Second, the analytical solution was validated through a comparison with the known literature. Finally, the assumptions that were made to simplify the model were verified by comparing the results with the comprehensive version of the model. The effect of the flow rate and the flow regime on the wellbore temperature profile are examined. The results showed a reverse effect of the flow rate on the bottom hole temperature within each flow regime. However, a significant increase in the bottom hole temperature is observed as the flow regime changed from laminar flow to turbulent flow. Changing the flow regime from laminar to turbulent will affect the value of the CHTC leading to a significant increase in wellbore fluid temperature. It is also shown that the maximum temperature at the annulus is located where the rate of heat exchange between the annulus and the pipe and the heat from the formation to the annulus is equal.

Guest Editorial: From Blockbuster to Blockchain: How to Manage a Not-Quite-Settled Technology Platform

Guest editorial In this era of Netflix and online media that can be accessed anywhere, it is easy to forget that we used to have to work a little harder to get entertained. In the first few years of the new millennium, a typical home movie experience often began with a trip to the local Blockbuster store. There was a bewildering array of plastic movie cases that you had to pick up and investigate before making your final selection. Upon reaching the cashier, the sales associate would retrieve the appropriate disc for your selected movie and put it in the box before sending you on your way. What made this ritual all the more challenging, however, was the fact that there was more than one type of disc format during the period 2006–2008. On one side of the store were the movies available for the HD DVD format, a technology platform led by Toshiba; on the other, movies for Sony’s Blu-ray machines. For the most part, the companies that produced movies had pledged allegiance to one of the formats or the other, but not to both of them. Blockbuster customers during this period were consequently faced with a dilemma. Everyone who had witnessed the drawn-out battle between VHS video tapes and Sony’s Betamax in the previous generation of Blockbuster products suspected that some kind of shakeout in the disc industry would probably happen eventually, and no one wanted to be left holding the bag with a disc player and movie collection tethered to the losing side. Thankfully, however, this problem was solved when Toshiba threw in the towel in 2008, leaving Sony’s platform as the undisputed winner in the movie disc technology war. This episode in the history of the entertainment industry is an important lesson to remember as we think about how to introduce blockchain into the oil and gas industry. Blockchain is essentially “a mathematical structure for storing data in a way that is nearly impossible to fake” (Orcutt, 2018), which makes it a useful way to reliably share all kinds of valuable information (Tapscott and Tapscott, 2016). In the finance sector, blockchain is most famously the technology underlying cryptocurrencies like Bitcoin, but new applications are being discovered all the time—including in the upstream oil and gas industry. Companies in the oil and gas sector have already made inroads into the blockchain domain by using the technology to improve trading (Braga, 2018), guarantee the authenticity of wellbore rock and fluid samples (Whitfield, 2018), and create a shared consensus about the progress of drilling campaigns (Rassenfoss, 2018). In fact, there is so much buzz and energy in the blockchain area these days that several consortia and research initiatives have popped up to figure out new and inventive ways to deliver value with it, including the Enterprise Ethereum Alliance and the Linux Foundation’s Hyperledger project (for both of which Intel was a founding member) or the Oil and Gas Blockchain Consortium.

Approach to Solving the Inverse Problem of Filtration Based on Descriptive Regularization

This paper presents the results of a study of inverse problem for the nonlinear parabolic equation for the fluid filtration in the fractured media. An approach to solve the inverse problem by using the descriptive regularization method is proposed. A mathematical model for the 3-D flow of a fluid through a pressure sensitive naturally fractured formation, with pseudosteady state matrix-fracture flow is developed. This model includes the effects of wellbore storage and fluid flow in the wellbore. A computational algorithm based on the proposed approach to estimate the dependence of the fractures permeability on pressure from the results of hydrodynamic studies of horizontal well is developed.

Fracture diagnostic using distributed temperature measurements during a pause in flow-back period

The significant temperature difference between the fractured and non-fractured regions during the stimulation fluid flow-back period can be very useful for fracture diagnosis. The recent developments in downhole temperature monitoring systems open new possibilities to detect these temperature variations to perform production logging analyses. In this work, we derive a novel analytical solution to model the temperature signal associated with the shut-in during flow-back and production periods. The temperature behavior can infer the efficiency of each fracture. To obtain the analytical solution from an existing wellbore fluid energy balance equation, we use the Method of Characteristics with the input of a relevant thermal boundary condition. The temperature modeling results acquired from this analytical solution are validated against those from a finite element model for multiple cases.Compared to the warm-back effect in the non-fractured region after shut-in, a less significant heating effect is observed in the fractured region because of the warmer fluid away from the perforation moving into the fracture (after-flow). Detailed parametric analyses are conducted on after-flow velocity and its variation, flowing, geothermal, and inflow temperature of each fracture, surrounding temperature field, and casing radius to investigate their impacts on the wellbore fluid temperature modeling results.The inversion procedures characterize each fracture considering the exponential distribution of temperature based on the analytical solutions in fractured and non-fractured regions. Inflow fluid temperature, surrounding temperature field, and after-flow velocity of each fracture can be estimated from the measured temperature data, which present decent accuracies analyzing synthetic temperature signal. The estimations are independent on each cluster, which can be combined to analyze the entire production section. The outputs of this work can contribute to production logging, warm-back, and wellbore storage analyses to achieve successful fracture diagnostic.

A Coupled Transient Wellbore/Reservoir-Temperature Analytical Model

Summary This work presents a new coupled transient wellbore/reservoir thermal analytical model, consisting of a combined reservoir/casing/tubing system. The analytical model considers flow of a slightly compressible, single–phase fluid in a homogeneous infinite–acting reservoir system and provides temperature–transient data for drawdown and buildup tests at any gauge location along the wellbore. The model accounts for Joule–Thomson (J–T), adiabatic–fluid–expansion, conduction, and convection effects. The wellbore–fluid mass density is modeled as a function of temperature, and the analytical solution makes use of the Laplace transformation to solve the transient heat–flow differential equation, accounting for a transient wellbore–temperature gradient ∂T/∂z. The solutions presented assume moderate– to high–permeability reservoirs and do not consider skin effects in the formation. Results of the analytical model are compared with those of a commercial thermal simulator and with those of available models in the literature. Our model provides more accurate transient–temperature–flow profiles along the wellbore in comparison with previous analytical models in the literature. Furthermore, a generalization of a well–known parameter–estimation method from transient–temperature data is provided.

Numerical analysis of transient wellbore thermal behavior in dynamic deepwater multi-gradient drilling

This paper aims to investigate the wellbore thermal behavior in multi-gradient drilling (MGD). Based on the principle of energy conservation, a synthetic transient heat transfer model was established, in which the mass and heat transfer of lightweight glass microspheres (GMSs) were considered for the wellbore fluid region, and the dynamic variation in the moving boundary was considered for the drill bit and separator region. The synthetic model was solved using the combination of finite volume method and dynamic laying method. The accuracy and capability of the model were verified using field measurement data and previous typical models. The calculation results suggested that the annular temperature near the separator dropped suddenly due to the mass and heat transfer of GMSs. Additionally, the dynamic drilling of the drill bit would increase the bottomhole temperature continuously. Furthermore, a sensitivity analysis indicated that when the GMS concentration increased from 5% to 45%, the annulus temperature at the separator reduced by 9.15%; when the distance between the drill bit and separator increased from 1100 m to 3000 m, the bottomhole temperature increases by 3.99%; and the effect of the separator number on annulus temperature combined the dual role of separator position and GMS concentration.

Study on wellbore fluid flow and heat transfer of a multilateral-well CO2 enhanced geothermal system

Research efforts towards CO2 enhanced geothermal systems (CO2-EGS) are increasing due to potentially high heat extraction efficiencies. It is well known that CO2 properties are highly sensitive to the temperature and pressure and have noticeable effects on CO2-EGS heat extraction. Consequently, an understanding of wellbore CO2 fluid flow and heat transfer mechanisms is necessary when considering variable CO2 properties. In this paper, a coupled wellbore and reservoir fluid flow and heat transfer model is used to estimate multilateral-well CO2-EGS efficiency. The model is calibrated and validated by field data from the HGP-A well in Hawaii. Schematically, concentric tubulars are used allowing single well injection and production. Multiple cases are analyzed using this model. These include effects of CO2 pressure work on wellbore CO2 fluid flow and heat transfer, assessment of differences in heat extraction using varying wellbore sizes and central tubing insulation lengths, and evaluations of efficiencies under different injection-production well configurations. Results show that CO2 pressure work can induce a dramatic temperature reduction in the central tubing of the multilateral-well CO2-EGS. The majority of pressure loss occurs in the formation and central tubing. The optimized design suggests that a three-layer central tubing with a central diameter of 0.19 m will maximize heat insulation and heat extraction. The effect of annulus diameter on heat extraction is negligible. Also, a lower injection well configuration results in a higher outlet temperature, thermal power output, and lower pressure losses compared to an upper injection well configuration. These results provide significant suggestions for wellbore designs that can potentially optimize multilateral-well CO2-EGS efficiency.

Energy efficiency of well electric submersible pumps for oil production

Downhole artificial lift is the most energy-intensive process at the oil companies. In the current economic conditions, the oil companies are forced to optimize the power consumption for production processes. To do this, you must have a methodology for calculating the energy consumption of all oil-producing equipment. Energy losses occur in all parts of the electrical submersible pump units: submersible motors, electrical cables, transformers and control station. There are analytical expressions that allow finding the power consumption in all elements of the pumping unit. However, the energy consumption depends on many process and operating parameters, such as density, viscosity, water content wellbore fluid, gas content, temperature in the borehole. The authors conducted a study on the impact on the power consumption of various technological and operational parameters. When adjusting the pump performance varies depression and reservoir, respectively, and the oil recovery wells. Therefore, to determine the optimal performance of the pump for the payment by a particular well is problematic. The relationship between the formation and the depression change inflow well fluid can be determined according to well testing. The results of this research can be useful to specialists in the development of the oil-producing enterprises of measures to optimize energy consumption.

Modeling the flow of carbon dioxide during the drilling of oil, gas, and geothermal energy

Using carbon dioxide as a resource for enhancing the exploitation of fossil energy and geothermal energy, while realizing the geological storage of carbon dioxide, is an important direction in carbon dioxide capture, utilization, and storage studies. A carbon dioxide wellbore flow model is developed by considering the wellbore heat transmission, fluid dynamics, potential energy, and viscous friction heat. The flow characteristics of carbon dioxide and the controllable influence factors of the bottom hole pressure under different geothermal gradients are analyzed. The results indicate that the liquid carbon dioxide pumped into the drill-string enters the supercritical state at a depth of 454.8 m, and returns to the liquid state at a depth of 439.8 m in the annulus under the conditions stated here. The geothermal gradient has a significant influence on the density, pressure, and state of carbon dioxide in both the drill-string and the annulus. A larger choke pressure at the wellhead and a higher flow rate are required to obtain the same target bottom hole pressure under a high geothermal gradient. The injecting temperature has little influence on the pressure profile in the annulus. We herein establish a solid theoretical foundation for drilling technology with carbon dioxide.

An Advanced Coupled Rock–Fluid Computational Model for Dynamic–Radial Mud Filtration with Experimental Validation

Drilling mud filtration occurs during an overbalanced drilling activity and concurrently with mud loss through pore throats and fractures. Mud loss and filtration are increased when the wellbore fluid condition is in a dynamic mode (pipe rotation and/or fluid circulation), rather than static. Formation damage is a critical industry challenge that results from mud loss and filtration. There is a considerable amount of experimental studies with only a few modeling approaches for characterizing dynamic mud filtration. Most of these studies have not accounted for factors that can exacerbate mud filtration which includes but not limited to: temperature, pipe rotation, pip/wellbore geometry/eccentricity, and porous media complexity. In this study, two mathematical and computational modeling approaches that can be used to predict dynamic drilling mud filtration in a radial coordinate system are presented. In the first modeling approach, a mechanistic model that is based on a material balance of filter cake evolution is presented. Critical factors that impact dynamic–radial mud filtration (temperature, rotary speed, rock permeability, and rock porosity) and other factors (wellbore/reservoir dimensions, filter cake properties, and mud/filtrate rheological properties at reservoir temperature) were accounted for. The model was solved with a numerical approach and commercial software. In the second approach, a scanning electron microscopy image of selected dry core samples, combined with image processing, was used to estimate the pore size and porosity of the internal filter cake. The pore structure of the rock samples and filter cake was modeled using the bundle of curved tubes approach. The deposition probability of mud particles was considered through filtration theories. The modeling results were validated with dynamic–radial filtration experiments. The results from both models closely matched the experimental results. On average, the models revealed no more than 4% relative error in predicting dynamic mud filtration. The novelty in both approaches is the incorporation of critical parameters in the models over a wide range and their responses to cumulative filtrate invasion in different rock types.

Estimating the initial-formation temperature and flowing-temperature gradient with transient-temperature analysis: Applications in gas reservoirs

The formation temperature constitutes one of the essential factors that affect the wellbore fluid temperature behavior in production mode. The amount and direction of the radial heat transfer between the surrounding formation and the wellbore depend on the temperature differential and thermal properties of the media.Traditional studies probing geothermal gradients depended principally on extrapolating the transient bottomhole temperature to infinite shut-in time for obtaining the undisturbed formation temperature. After that, a straight line from the surface to the bottomhole condition constituted the geothermal gradient. Of course, the implicit assumption in this approach is that a linear geothermal gradient exists in light of unavailability of depth-wise temperature measurements.This study presents a new transient-temperature analysis approach to determine the undisturbed formation temperature. Specifically, we show the application of the line-source solution that has roots in the temperature-diffusivity equation. Secondly, using the distributed temperature measurements associated with transient-pressure testing, we proved that the bottomhole or static temperature is time-dependent, leading to alteration of the geothermal gradient in a well's proximity. Finally, the lowering of the temperature-derivative plateau with increasing depth during well shut-in periods indicated an increase in thermal conductivity, resulting in a nonlinear geothermal gradient.

A coupling model of water breakthrough time for a multilateral horizontal well in a bottom water-drive reservoir

A series of complex production wells have been applied in challenging reservoirs to maximize oil recovery. Multilateral horizontal well has received plentiful attentions in recent years. The multilateral horizontal well technology is especially beneficial in expanding formation drainage area, reducing water cresting and coning, increasing productivity, and postponing water breakthrough time in bottom water reservoir. Since Muskat and Wyckoff introduced the concept of water coning into petroleum engineering field, different models have been proposed to forecast the critical rate and water breakthrough time for vertical and horizontal wells. However, the studies of water breakthrough time for complex structured multilateral horizontal wells have rarely been reported. This paper proposes a new coupling model for estimating the water breakthrough time of complex structured multilateral horizontal wells. The proposed model took multiple factors into account, including the wellbore 3D structure, wellbore vertical location, and reservoir and fluids properties. In addition, a field case study was conducted by utilizing the methods that were proposed in this paper. The practical production data was compared with the results obtained from the analytical model, and this coupling model shows an excellent agreement with the results from the actual scenarios. The proposed methods in this paper can be utilized to forecast the water breakthrough time and breakthrough locations of multilateral wells in bottom water reservoirs.

Investigating the pressure characteristics and production performance of liquid-loaded horizontal wells in unconventional gas reservoirs

The increasing exploiting activities in unconventional gas reservoirs renew the interests of investigating liquid loading phenomenon, a common production issue for gas wells. Most previous studies focused on predicting the onset of liquid loading. The reservoir pressure characteristics and wellbore production performance after the onset of liquid loading have not been systematically investigated. This work introduces a newly developed fully implicitly coupled wellbore reservoir model to investigate the liquid loading effects on horizontal wells in low permeability gas reservoirs. The model honors the mass and momentum balances in both reservoir and wellbore systems, and thus allows us to analyze both wellbore and reservoir dynamics after the onset of liquid loading. The simulation results reveal that horizontal gas wells in low permeability reservoirs might experience natural cyclical production after the onset of liquid loading, which coincides with field observations. Both uniform stimulation and hydraulic fracturing help mitigate the cyclical production phenomenon. The near-wellbore reservoir pressure buildup and wellbore fluid reinjection are also evaluated. This work demonstrates the successful application of the coupled wellbore reservoir model in predicting the rich production phenomena of stimulated horizontal wells after the onset of liquid loading.

Temperature and Borehole-Wall Stress Fields of Gas Drilling

Air drilling technology in some cases improves wellbore penetration and stability. The annulus gas temperature is usually regarded to be the same as the formation temperature. However, the gas temperature is greatly influenced by the pressure and in situ viscosity because of its compressibility. Joule—Thompson expansion and cooling as the gas passes through the bit nozzles causes the gas temperature to differ significantly from that of the formation. In the present paper, a method for calculating pressure—temperature coupling over the whole wellbore is proposed. Radial and tangential thermal stresses are determined considering heat exchange between wellbore fluid and the formation. Then, the wellbore wall stability under the influence of the thermal stresses is analyzed. The calculated wellbore-rock and thermal stresses show that the low temperature in the well bottom causes tensile stresses around the wellbore wall. Therefore, shear stresses in the rock, the effective stress of the wellbore wall, and the collapse pressure decrease, which has a positive effect on the wall stability.