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Geothermal energy, being a clean energy source, has immense potential, and accurate wellbore modeling is crucial for optimizing the drilling process and ensuring safety. This paper presents a novel geothermal wellbore model based on the drift-flux approach, tested under three different temperature and pressure well conditions. The proposed model integrates the conservation equations of mass, momentum, and energy, incorporating the gas–liquid two-phase flow drift-flux model and heat transfer model. The key features include handling the heat transfer between the formation and the wellbore, addressing the slip relationship between the gas and liquid phases, and accounting for wellbore friction. The nonlinear equations are discretized using the finite difference method, and the highly nonlinear system is solved using the Newton–Raphson method. The numerical simulation, validation, and comparison with existing models demonstrate the enhanced accuracy of this model. In our tests, the model achieved a high accuracy in calculating the bottom-hole pressure and temperature, with mean relative errors (MREs) significantly lower than those of other models. For example, the MREs for the bottom-hole pressure and temperature of the Rongxi area well in Xiongan, calculated by this model, are 1.491% and 1.323%, respectively. These results offer valuable insights for optimizing drilling parameters and ensuring drilling safety. Comparisons indicate that this approach significantly outperforms others in capturing the complex dynamics of geothermal wellbores, making it a superior tool for geothermal energy development. [ABSTRACT FROM AUTHOR]

Computer aided design of a horizontal well without flush tubes providing optimal operating conditions with regard to varying pressure along horizontal well length, to the presence of deviated and slant segments is considered. As a result a well-head pressure - flow rate plot is computed. Allowable values of bottom-hole pressure, of horizontal segment lengths and diameters that ensure transport of solid particles are taken into account when building well-head pressure - flow rate plot.

The present study aims at investigating the effect of temperature variation due to heat transfer between the formation and drilling fluids considering influx from the reservoir in the underbalanced drilling condition. Gas-liquid-solid three-phase flow model considering transient thermal interaction with the formation was applied to simulate wellbore fluid to calculate the wellbore temperature and pressure and analyze the influence of different parameters on fluid pressure and temperature distribution in annulus. The results show that the non-isothermal three-phase flow model with thermal consideration gives more accurate prediction of bottom-hole pressure (BHP) compared to other models considering geothermal temperature. Viscous dissipation, the heat produced by friction between the rotating drilling-string and well wall and drill bit drilling, and influx of oil and gas from reservoir have significant impact on the distribution of fluid temperature in the wellbore, which in turn affects the BHP. Bottom-hole fluid temperature decreases with increasing liquid flow rate, circulation time, and specific heat of liquid and gas but it increases with increasing in gas flow rate. It was found that BHP is strongly depended on the gas and liquid flow rates but it has weak dependence on the circulation time and specific heat of liquid and gas. BHP increase with increasing liquid flow rate and decreases with increasing gas flow rate.

Gas reservoirs discovered in the southern margin of the Junggar Basin generally have high temperatures (up to 172.22 °C) and high pressures (up to 171.74 MPa). If using the PVT laboratory to get the gas compressibility factor, data from the laboratory are so little that it will not satisfy the demands of reservoir engineering calculations. There are many empirical correlations for calculating the Z-factor; however, these correlations give large errors at high gas reservoir pressures. The errors in estimating the Z-factor will lead to large errors in estimating all the other gas properties such as gas formation volume factor, gas compressibility, and gas in place. In this paper, a new accurate Z-factor correlation has been developed based on PVT data by correcting the high-pressure part of the most commonly used Dranchuk-Purvis-Robinson Correlation. Multivariate nonlinear regression is used to establish the independent variable function of pseudo-critical temperatures and pressures. By comparing it with the PVT data, the DPR correlation is continuously corrected to be suitable for ultra-deep gas reservoirs with HTHP. The new correlation can be used to determine the Z-factor at any pressure range, especially for high pressures, and the error is less than 1% compared to the PVT data. Then, based on the corrected Z-factor, the Cullender-Smith method is used to calculate the bottom hole pressure in the middle of the reservoir. Finally, the Z-factor under reservoir conditions of well H2 is predicted and the Z-factor chart at different temperatures is provided. [ABSTRACT FROM AUTHOR]

Although horizontal well system has great advantages in methane production from clayey silt hydrate reservoir, borehole collapse is easy to occur during the drilling operation, which can seriously affect the drilling safety and efficiency. However, previous investigations have failed to thoroughly explore the mechanism of borehole collapse in horizontal well system. In this study, numerical investigation on collapse behavior of different boreholes within the horizontal well system in hydrate reservoir was conducted. It is found that borehole enlargement rate of both injection wells and production wells in horizontal well system decreases with the increase of drilling fluid density. However, due to the faster dissociation rate of natural gas hydrates, borehole enlargement rate is often higher in injection wells as compared to production wells. Based on the investigation results of borehole stability, lower limit of the safe mud weight window for horizontal well system was determined by considering different acceptable borehole enlargement rates. After analysis, it was found that the lower limit of the safe mud weight window depends on the mud density of the injection well for a specific acceptable borehole expansion rate. Moreover, the lower limit of safe mud weight window needs to be designed larger with improvement of the requirement for wellbore stability (i.e., decrease of acceptable borehole enlargement rate). For example, when acceptable borehole enlargement rate changes from 20 to 5%, the lower limit of the safe mud weight window needs to be increased from 1.007 to 1.047. Investigations in this paper will play a significant role in preventing serious borehole instability during drilling operation in hydrate reservoirs. [ABSTRACT FROM AUTHOR]

When oil fields reach the high water-cut stage or in late development, the multiphase flow of oil/gas or oil/water, even oil/gas/water will occur in a reservoir. The conventional well test approaches are no longer applicable to this situation. Many studies have been done on multiphase well testing, including traditional multiphase flow well testing and numerical well testing approaches. In focusing on traditional multiphase flow well testing approaches, this work builds a 3D model using Eclipse software to examine the pressure response on a well located in the center of an anticline reservoir with a closed system. The results show that the Perrine-Martin (P-M) approach is the simplest one and is suitable for all reservoir systems. While the pressure-squared approach is only suitable for low rate conditions in an oil–water system. Pseudo-pressures are complicated and can only be used in a gas–oil system. [ABSTRACT FROM AUTHOR]

Copyright of Journal of China University of Petroleum is the property of China University of Petroleum and its content may not be copied or emailed to multiple sites or posted to a listserv without the copyright holder's express written permission. However, users may print, download, or email articles for individual use. This abstract may be abridged. No warranty is given about the accuracy of the copy. Users should refer to the original published version of the material for the full abstract. (Copyright applies to all Abstracts.)

Knowing the effects of different parameters on the drilling fluid is an essential part of a successful and safe drilling operation. High pressure and high temperature conditions have opposing effects on the fluid density which has an important effect on the bottom-hole pressure. So for estimating precise bottom-hole pressure, it is essential to take into account these opposite effects on drilling fluid compression or expansion. In this study, Bingham-plastic model is considered as drilling fluid to simulate drilling operation and develop temperature and pressure distribution through the wellbore. The effects of variation in drilling fluid flow rate, drilling fluid specific heat and inlet mud temperature are explored and discussed for an oil-based mud. Also, the effects of frictional pressure loss, pressure loss in the drill bit and, drill string rotation are considered as internal heat sources in the wellbore. Results show that thermal interaction is required for accurate prediction of the bottom-hole pressure. Variations of different parameters change temperature distribution in the wellbore which consequently changes the bottom-hole pressure. The results show that considering the variation of rheological properties, bottom-hole pressure prediction may change as much as 685 psi (about 2.30%) which is considerable. Model predictions were compared with the field data for validation of the model. [ABSTRACT FROM AUTHOR]

During the drilling process, measured bottom-hole pressure data were prone to distortion and even no data are fed back, besides, the bottom-hole pressure calculation model could not reflect the live measured values. As a consequence, inaccurate bottom-hole pressure monitoring would bring enormous safety risks to drilling operations. Data mining was an advanced method used to sort out, discover and set up models from large relevant data sets. In the monitoring of bottom-hole pressures, it was necessary to conduct an effective and overall monitoring during the drilling process. Therefore, this paper proposed the k-means clustering method to optimize Naive Bayesian models in combination with the bottom-hole pressure monitoring theory, a k-means clustering optimized Naive Bayesian model for implementation of intelligent dynamic analysis of bottom-hole pressure was established. Such model could be utilized for correcting bottom-hole pressures calculated by the traditional hydraulic model, and then the corrections were taken for comparison with measured bottom-hole pressures so as to make calculations be of minimal errors. Field data were also taken for analysis, and the results suggested that the k-means based Naive Bayesian models for correction to calculated bottom-hole pressures had smaller deviations which fell within safe deviation monitoring range of drilling pressures, and could meet the requirements of normal drilling operation. [ABSTRACT FROM AUTHOR]

CO2 reservoirs and high CO2 content gas reservoirs in marine sediments generally have complex pressure system, which usually encounters supercritical CO2(SC‐CO2) invasion into the wellbore during drilling process. The wellbore transient flow and phase transition along the wellbore during the drilling process has not been thoroughly investigated, because the CO2 physical properties and the reservoirs petrophysical properties could affect the transient flow of mixed fluid and phase transition of CO2 along the well. A numerical model is presented in this research to analyze the transient flow in wellbores and to predict phase transition of CO2 during formation SC‐CO2 invasion in the drilling process. The main considerations were the following: multiphase transient flow in wellbores was coupled with the non‐Darcy flow through the formation; wellbore temperature, pressure and the mixture of drilling fluid and SC‐CO2 were calculated in the method of coupling; the invaded SC‐CO2 could affect the mixed fluid physical properties in the annulus; the change of physical properties of CO2 (eg, solubility, phase transition) was considered and integrated. The research results indicate that as the mixture of drilling fluid and SC‐CO2 flows from the bottom to the surface, the invaded CO2 is difficult to be detected at the early invasion stage because of high CO2 density and solubility; the CO2 would change from supercritical to gas phase and the dissolved quantity and density of CO2 rapidly decrease near the wellhead, and further cause well‐control issues. Furthermore, the bottom‐hole pressure (BHP) would decrease and could not provide sufficient balance to the formation pressure, which could significantly increase the risk of well blowout. Sensitivity analysis was utilized to evaluate the effects of the choke pressure, drilling fluid pumping rate, initial pressure difference, reservoir permeability, and drilled reservoir thickness on the BHP and the depth of phase transition of CO2. A numerical model coupling the flow‐temperature distribution in wellbores with the non‐Darcy seepage through formation media was formulated to study the transient multiple‐phase flow during SC‐CO2 invasion. With proposed numerical method and field data, the characteristics of gas‐liquid two‐phase transient flow and phase transition of CO2 were further investigated. The mechanisms for well blowout triggered by solubility variation and phase transition of CO2 were studied. [ABSTRACT FROM AUTHOR]

During methane production induced by depressurization, significant mechanical responses of hydrate‐bearing sediment (HBS) such as large volume contraction and subsidence can possibly be generated. Moreover, this phenomenon is further exacerbated by strength and stiffness reduction in the HBSs as hydrate dissociation advances. As a result, the highest compressive strength is concentrated in the vicinity of the production wellbore. Therefore, it is essential to address and evaluate the mechanical responses of HBSs and conduct a stability analysis of the production well during depressurization and hydrate dissociation to prevent the destruction of production facilities and consequent leakage of methane gas. In this study, a reservoir‐scale thermal‐hydraulic‐mechanical coupled simulation using FLAC3D (Fast Lagrangian Analysis of Continua in 3 Dimensions) was conducted to evaluate the mechanical responses of HBSs and the stability of a wellbore during methane production by depressurization at the Ulleung Basin. The structural design and mechanical properties including the dimensions of wellbore components and interface properties related to the interaction behavior between the sediment and wellbore were considered in the three‐dimensional model. Key Points: A reservoir‐scale 3‐D simulation was developed to evaluate wellbore instability by depressurization‐induced hydrate dissociationThe structural design and properties including the interface properties of the wellbore and its assembly were considered in the simulationThe allowable bottom‐hole pressure was recommended to avoid compressive failure of the well assembly during the production period [ABSTRACT FROM AUTHOR]

The purpose of this paper is to discuss the variation of wellbore temperature and bottom-hole pressure with key factors in the case of coupled temperature and pressure under multi-pressure system during deep-water drilling circulation. According to the law of energy conservation and momentum equation, the coupled temperature and pressure calculation model under multi-pressure system is developed by using the comprehensive convective heat transfer coefficient. The model is discretized and solved by finite difference method and Gauss Seidel iteration respectively. Then the calculation results of this paper are compared and verified with previous research models and field measured data. The results show that when the multi-pressure system is located in the middle formation, the temperature of the annulus corresponding to location of the system is the most affected, and the temperature of the other areas in annulus is hardly affected. However, when the multi-pressure system is located at the bottom hole, the annulus temperature is greatly affected from bottom hole to mudline. In addition, the thermo-physical parameters of the drilling fluid can be changed by overflow and leakage. When only overflow occurs, the annulus temperature increases the most, but the viscosity decreases the most. When only leakage occurs, the annulus temperature decreases the most and the viscosity increases the most. However, when the overflow rate is greater than the leakage rate, the mud density and bottom-hole pressure increase the most, and both increase the least when only leakage occurs. Meanwhile, bottom-hole pressure increases with the increase of pump rate but decreases with the increase of inlet temperature. The research results can provide theoretical guidance for safe drilling in complex formations such as multi-pressure systems.

Abstract: Most risk analysis approaches are static; failing to capture evolving conditions. Blowout, the most feared accident during a drilling operation, is a complex and dynamic event. The traditional risk analysis methods are useful in the early design stage of drilling operation while falling short during evolving operational decision making. A new dynamic risk analysis approach is presented to capture evolving situations through dynamic probability and consequence models. The dynamic consequence models, the focus of this study, are developed in terms of loss functions. These models are subsequently integrated with the probability to estimate operational risk, providing a real‐time risk analysis. The real‐time evolving situation is considered dependent on the changing bottom‐hole pressure as drilling progresses. The application of the methodology and models are demonstrated with a case study of an offshore drilling operation evolving to a blowout. [ABSTRACT FROM AUTHOR]

In this study, gas-liquid-solid three-phase flow in the annulus of a well with actual dimensions is simulated numerically considering under-balanced drilling (UBD) operations. The multi-fluid approach which is the most accurate and sophisticated method is used for the simulation. For this purpose, one-dimensional form of steady-state three-fluid model in the Eulerian frame of reference is used to simulate the three-phase flow in the UBD operation. The results have been validated with actual field data and also with the result of gas-liquid two-phase flow model. The comparisons show that three-phase numerical simulation gives better accuracy compared to two-phase numerical simulation and most of other models which are using mechanistic approach. Given the importance of the prediction and control of the bottom-hole pressure (BHP) during drilling operations, the effects of controlling parameters such as liquid and gas flow rate, drilling velocity, size of cuttings and choke pressure on the BHP are investigated. Also, due to the importance of the hole-cleaning during drilling operations, the effects of different controlling parameters on the solid volume fraction distribution during annulus are discussed. Results show that the increasing of the gas flow rate and decreasing of the cutting size can be used as a tool for improved hole-cleaning in the UBD operation. [ABSTRACT FROM AUTHOR]

Most risk analysis of drilling operations failed to distinguish and capture evolving risk during different stages of drilling operations. This paper presents a new integrated dynamic risk analysis methodology. This methodology comprises models applicable at different stages of drilling operations. These models capture evolving situations in terms of changes in the probability and consequences of unwanted scenario (unstable well condition). The dynamic consequence models are developed in terms of loss functions dependent on changing bottom-hole pressure during different stages of drilling operation. The proposed methodology is tested using real life case. It is observed that the proposed methodology help monitoring and maintaining well stability during different stages of drilling operations. [ABSTRACT FROM AUTHOR]

Hydraulic fracturing operations have been viewed as the cause of certain environmental issues including groundwater contamination. The potential for hydraulic fracturing to induce contaminant pathways in groundwater is not well understood since gas wells are completed while isolating the water table and the gas-bearing reservoirs lay thousands of feet below the water table. Recent studies have attributed ground water contamination to poor well construction and leaks in the wellbore annulus due to ruptured wellbore casings. In this paper, a geospatial model of the Barnett Shale region was created using ArcGIS. The model was used for spatial analysis of groundwater quality data in order to determine if regional variations in groundwater quality, as indicated by various groundwater constituent concentrations, may be associated with the presence of hydraulically fractured gas wells in the region. The Barnett Shale reservoir pressure, completions data, and fracture treatment data were evaluated as predictors of groundwater quality change. Results indicated that elevated concentrations of certain groundwater constituents are likely related to natural gas production in the study area and that beryllium, in this formation, could be used as an indicator variable for evaluating fracturing impacts on regional groundwater quality. Results also indicated that gas well density and formation pressures correlate to change in regional water quality whereas proximity to gas wells, by itself, does not. The results also provided indirect evidence supporting the possibility that micro annular fissures serve as a pathway transporting fluids and chemicals from the fractured wellbore to the overlying groundwater aquifers. [ABSTRACT FROM AUTHOR]

Copyright of Oil Drilling & Production Technology / Shiyou Zuancai Gongyi is the property of Shiyou Zuancai Gongyi Bianjibu and its content may not be copied or emailed to multiple sites or posted to a listserv without the copyright holder's express written permission. However, users may print, download, or email articles for individual use. This abstract may be abridged. No warranty is given about the accuracy of the copy. Users should refer to the original published version of the material for the full abstract. (Copyright applies to all Abstracts.)

Modeling and simulation of gas-liquid two-phase flow in under-balanced drilling (UBD) operation is very important in order to accurately predict the bottom-hole pressure (BHP) and other parameters of two-phase flow. In this paper one-dimensional form of steady-state two-fluid model in the Eulerian frame of reference is used to simulate the two-phase flow in the UBD operation. Simulation is performed to calculate the parameters such as pressure, volume fraction and velocities of two phases at different flow regimes, namely bubbly, slug and churn turbulent flow. The governing equations along with appropriate constitutive relations form a system of coupled ordinary differential equations (ODEs) which are solved using the well-known iterative Newton method. The effect of gas and liquid injection flow rates and also the choke pressure on the wellbore pressures, particularly on the BHP are investigated numerically. In order to validate the results of the current two-fluid model, they are compared with the actual field data and also with the results of the WELLFLO software using different mechanistic models. The comparisons show that the two-fluid model can accurately predict the BHP and other two-phase flow parameters. [ABSTRACT FROM AUTHOR]

The characteristics of adsorption/desorption of coal-bed methane, percolation mechanism and drainage control are important factors in the process of CBM production. The experiments on adsorption/desorption of CBM and characteristics of percolation were carried out in this study. The results show that the process of adsorption/desorption of CBM is reversible, while the "desorption hysteresis" occurs in the process. The seepage of CBM presents the characteristics of secondary percolation, which means that the seepage flow in coal matrix porosity is non-Darcy flow and the flow in natural fractures and large pore is Darcy flow. In addition, the study has found a phenomenon of "gas-water difference" in coal seams at a large scale development for the drainage decompression in the process of gas recovery. The gas yield is high with low water production at local high locations, while the water yield is high with low gas production at relatively low locations. At the same time, the damage process includes fast production, work over, stop pumping and shut-in and low fluid level below the top surface of coal seam can easily lead to pollutions which result in the sharp decrease of gas-water production. Its damage mechanism mainly includes pulverized coal jam damage, stress sensitivity damage, air lock damage and water lock damage. Based on the damage characteristics, damage mechanisms and many years' practical experience on CBM production, a drainage working system has been developed including draining with constant pressure, controlling a reasonable working pressure difference and maintaining a sound pulverized coal production rate. [ABSTRACT FROM AUTHOR]

The volume of the liquid penetrating into the formation after drilling-in has been determined on the basis of theoretical investigations. The dynamics of change in the bottom-hole pressure has been determined in this process. It has been shown that because of the water hammer, the bottom-hole pressure can be doubled in the presence of large fractures and pores closer to the well-bottom zone. [ABSTRACT FROM AUTHOR]

Abstract: The number of gas injection or exploitation projects is on fast increase with growing energy needs and environmental problems. Of these projects, the calculation and the control of wellhead pressure or bottom-hole pressure in wellbores are usually key steps. However, methods used to predict wellhead and bottom-hole pressure are multifarious, making the program writing and practical application inconvenient. In this study, a unified formula derived from the differential equations of one-dimensional steady pipe flow and applicable in both injection wells and production wells was presented for calculation of both wellhead pressure and bottom-hole pressure. The recalculation with a traditional numerical method of the same equations corroborated well the accuracy of the unified formula, and the positive- reverse checking calculation verified its reliability. Basic data from Shenhua CCS project were used for studying the influence of injected gas temperature, geothermal gradient and flow rate on wellbore pressure by applying the unified formula. The results can provide a technical guidance for practical operation. [Copyright &y& Elsevier]

A fast explicit finite difference method (FEFDM), derived from the differential equations of one-dimensional steady pipe flow, was presented for calculation of wellhead injection pressure. Recalculation with a traditional numerical method of the same equations corroborates well the reliability and rate of FEFDM. Moreover, a flow rate estimate method was developed for the project whose injection rate has not been clearly determined. A wellhead pressure regime determined by this method was successfully applied to the trial injection operations in Shihezi formation of Shenhua CCS Project, which is a good practice verification of FEFDM. At last, this method was used to evaluate the effect of friction and acceleration terms on the flow equation on the wellhead pressure. The result shows that for deep wellbore, the friction term can be omitted when flow rate is low and in a wide range of velocity the acceleration term can always be deleted. It is also shown that with flow rate increasing, the friction term can no longer be neglected. [ABSTRACT FROM AUTHOR]

Abstract: To predict bottom-hole pressure accurately and project the achievable production rate from a gas well with large accuracy, a modelling of solid flow effect on pressure drop in a vertical gas well is proposed. This model incorporates the effect of turbulence, solid transport and Moody friction factor, it is an extension of Adekomaya et al (2011) and Sukkar and Cornell method for determination of pressure drawdown in vertical gas well. The results obtained show that solid transport contributes significantly to pressure drop which other models fail to take cognizance of. The pressure drop is higher when solid accompanies the flowing fluid than when solid is not present. It is concluded that the greater the specific gravity of solid and solid holdup, the higher the pressure drop. [Copyright &y& Elsevier]

Abstract: Based on oil test and production test data of Sagizski complex small fault-block reservoir in Kazakhstan, this paper proposes systematic evaluation of reservoir dynamic characteristics and stable-development productivity equations, in view of reservoir early dynamic evaluation systems with oil test and production test materials. In association with dynamic production analysis, these paper studies convenient and feasible methods on the correction of calculation of bottom-hole pressure and test oil yield and determination of drive types of formation energy. In addition, this paper utilizes dynamic pressure data to more accurately estimate reserves, with the aim of providing a valid method for similar reservoirs early dynamic evaluation, which can effectively direct the setting of development programs and deployments. [Copyright &y& Elsevier]

Abstract: History matching of reservoir performance is difficult due to the uncertainties associated with reservoir properties. These uncertainties include the variety of geological model and fluid model. Usually, reservoir engineer changes geological properties to match history data, but ignore the changes of fluid properties, which may have a big influence on history matching. Considering a mature field entering high water-cut stage, for many infill wells, the well productivity can be obtained by stabilized well testing, but there is a phenomenon for drawdown (DD) test where the bottom-hole pressure (BHP) may increase with time when the water-cut reaches some value. In this situation, many reservoir engineers think this phenomenon was due to the change of production rate, the change of skin factor near wellbore or the interference of multi-wells. This paper excludes the interferences of these reasons, the objective of research focus on multiphase flow and explains the phenomenon from the viewpoint of multiphase flow. It is well known that the change of pressure on late time of well testing is closed to constant in closed system or closed to zero in constant pressure system. But under transient state, steady-state or semi-steady-state conditions, if the bottom-hole pressure goes up, then the DD data may not be used for well test analysis or reservoir engineering analysis. This paper presents study results on wells producing a multiphase reservoir by numerical well test model. According to Darcy''s Law, a new theoretical expression was derived in this situation, in which the derivative of bottom-hole flowing pressure is a function of integral of total mobility, which can be approximatively replaced of the average total effective mobility. Using this equation, the reason why well bottom-hole pressure increasing with time may be reasonably explained. According to the results of this study, under multiphase flow condition, the BHP increasing is due to the changing of the fluid total mobility, in this paper, it was further demonstrated that the data of this type can be used to adjust fluid model and improve history matching. [Copyright &y& Elsevier]

Integrated evaluation of bottomhole pressure (BHP) and water flow log (WFL) data from an undulating dual-lateral well provided significant insights into the contribution, flow performance, and injectivity of the well. This allowed for the setting of long-term performance characteristics for the well design in a multilayered reservoir. The injectivity test data (BHP pressure and injection profile) acquired in the first lateral and the drill stem testing (DST) data acquired in the second lateral were analyzed using a multilateral well modeling package designed for a multilayered reservoir. Useful and consistent interpretation not only increased confidence but also has assisted in making sound reservoir management decisions. Major observations out of this study include the following: The average vertical to horizontal permeability ratio ( k v / k h ), a difficult parameter to compute, in general, was determined with an excellent match spanning 10 injection and two fall-off periods in one lateral and four drawdowns and two buildups in the other.Injection profiles at two different water injection rates were predicted and compared with results based on reservoir saturation tool (RST)/WFL log. Excellent agreement was achieved. It is demonstrated that the agreement could be further improved if a nonconstant correction factor was used in interpreting RST/WFL log data.Well productivity and injectivity indices are dependent upon production/injection time and history. For both the well laterals, the late-time productivity/injectivity index equals around 11 STB/d/psi. [ABSTRACT FROM AUTHOR]

The balance relationship between bottom hole annulus pressure and formation pressure is a key factor to affect the drilling operation safety. Because of the complex and various situation underground, there is a big error between the actual bottomhole pressure and calculated one. The paper introduced a PWD system which can measure the parameters of weight on bit (WOB), torque, annulus pressure, annulus temperature, pressure inside the drill string, etc., and transmit the measurement data to the ground in real time. With the real time measurement data, the wellbore hydraulic model can be corrected in real time, and the underground situation can be interpreted in real time, what is more, the drilling accident can be predicted in real time. The field test proves the accuracy and reliability of the measurement system. Compared with the storage PWD system, this measurement system is more accurate, and has the function of transmitting the measured data in real time, so it can offer powerful technical support for drilling operation. [ABSTRACT FROM AUTHOR]

In the early production stage of coalbed methane (CBM) wells, especially in low permeability reservoirs, the method of shutting in casing annulus is usually adopted. However, the current commercial numerical simulation software fails to predict the dynamic performance of CBM wells under the control of both bottom-hole pressure and casing pressure. In this work, the calculation models of wellbore-pressure distribution and formation pressure distribution are derived firstly. Then, the above two models are coupled with several CBM dynamic performance analysis (CBMDPA) models developed in our previous researches, including pressure propagation model, water/gas productivity equations, dynamic permeability model, and material balance equation. A new CBMDPA program is developed with the coupling model, which can simulate the dynamic production performance of CBM wells after inputting the basic reservoir and fluid parameters, casing pressure, and bottom-hole pressure. Next, the newly developed CBMDPA program is validated against four field cases in China, and excellent agreements are obtained. The inputs of our CBMDPA program include casing pressure, bottom-hole pressure, and some deterministic and uncertain reservoir and fluid parameters. By adjusting the uncertain parameters, the gas production history can be fitted, and the uncertainty on the determination of reservoir properties can be addressed. On this basis, the future gas production is predicted using the determined parameters and the scheduled bottom-hole pressure and casing pressure. Finally, the influence of casing pressure on gas production is studied. Results show that high casing pressure has detrimental impact on the maximum daily gas production, while, it plays a positive role to achieve great desorption area, which will further prolong the stable gas production period. Under the high casing pressure of 2.5 MPa, the maximum daily production is decreased by about 54%, but the stable production stage is prolonged to more than 3000 days. It indicates that an appropriate range for casing pressure is favorable, considering both the accumulative gas production and the desorption area. For the case with representative properties from Muai block, the casing pressure is suggested to be 1–2 MPa, and the range between 1 MPa and 1.5 MPa is recommended for Hancheng block. • A coupling model for dynamic performance prediction of CBM wells is proposed. • The wellbore pressure distribution and liquid level variation is considered. • CBM production under the control of the casing pressure is simulated. • The developed software is validated through history matching on real CBM wells. • There exists an appropriate range of casing pressure for CBM production. [ABSTRACT FROM AUTHOR]

• Analysis uses amplitude of BHP and BHT changes during the preceding injection event, in conjunction with a temperature Horner plot. • Workflow produces estimate of slope of pressure Horner plot which can be used to calculate permeability. Although bottom-hole temperature (BHT) data is routinely collected with bottom-hole pressure (BHP) data during CO 2 injection in geological storage projects, it is seldom analyzed in a quantitative manner. However, the BHP and BHT signals do exhibit correlated behavior. This study proposes a practical approach for using BHT data from warmback (no injection) periods, in conjunction with the amplitude of BHP and BHT changes during the preceding injection event, to estimate formation permeability. The methodology is demonstrated using data from the AEP Mountaineer project in USA where CO 2 injection was carried out into a saline aquifer. Estimated permeability values from the proposed approach are in good agreement with those obtained from transient pressure analysis of BHP data from the falloff period. [ABSTRACT FROM AUTHOR]

The purpose of this paper is to discuss the variation of wellbore temperature and bottom-hole pressure with key factors in the case of coupled temperature and pressure under multi-pressure system during deep-water drilling circulation. According to the law of energy conservation and momentum equation, the coupled temperature and pressure calculation model under multi-pressure system is developed by using the comprehensive convective heat transfer coefficient. The model is discretized and solved by finite difference method and Gauss Seidel iteration respectively. Then the calculation results of this paper are compared and verified with previous research models and field measured data. The results show that when the multi-pressure system is located in the middle formation, the temperature of the annulus corresponding to location of the system is the most affected, and the temperature of the other areas in annulus is hardly affected. However, when the multi-pressure system is located at the bottom hole, the annulus temperature is greatly affected from bottom hole to mudline. In addition, the thermo-physical parameters of the drilling fluid can be changed by overflow and leakage. When only overflow occurs, the annulus temperature increases the most, but the viscosity decreases the most. When only leakage occurs, the annulus temperature decreases the most and the viscosity increases the most. However, when the overflow rate is greater than the leakage rate, the mud density and bottom-hole pressure increase the most, and both increase the least when only leakage occurs. Meanwhile, bottom-hole pressure increases with the increase of pump rate but decreases with the increase of inlet temperature. The research results can provide theoretical guidance for safe drilling in complex formations such as multi-pressure systems. [ABSTRACT FROM AUTHOR]

Most risk analysis approaches are static; failing to capture evolving conditions. Blowout, the most feared accident during a drilling operation, is a complex and dynamic event. The traditional risk analysis methods are useful in the early design stage of drilling operation while falling short during evolving operational decision making. A new dynamic risk analysis approach is presented to capture evolving situations through dynamic probability and consequence models. The dynamic consequence models, the focus of this study, are developed in terms of loss functions. These models are subsequently integrated with the probability to estimate operational risk, providing a real-time risk analysis. The real-time evolving situation is considered dependent on the changing bottom-hole pressure as drilling progresses. The application of the methodology and models are demonstrated with a case study of an offshore drilling operation evolving to a blowout., (© 2017 Society for Risk Analysis.)