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Wellbores are comprised by a steel casing surrounded by a cement sheath. The microannulus is the typically very small annular or degraded space that may develop between cement and casing that has been identified as a common leakage pathway in wellbore systems. Although data regarding the actual size and character of wellbore microannuli are limited, the hydraulic aperture of the microannulus can be estimated from pressure build up or flow measurements at the wellhead. Such information can be misleading, however, as it represents microannuli as uniform annular gaps along the wellbore. This study aims to provide a quantitative measure of the variability of the microannuli. We generated wellbore-based samples with microannuli between the steel casing and cement, and calculated their hydraulic aperture and permeability by flowing gas through the microannuli. We then injected dyed epoxy into the microannuli, cut the specimens into five circumferential sections per sample, and used microphotographs to measure microannulus aperture size and contact between the steel and the cement to generate microannulus profiles for each section. These measurements are unique as they provide a quantitative measure of the variability of the microannulus with a resolution as low as 3 μm. Aperture sizes were fitted to different statistical distributions, most frequently lognormal and gamma. Capillary entry pressure (CEP) for gas displacing brine in the microannulus was estimated from measured aperture size. CEP estimated from actual aperture size was generally much greater than that estimated from the hydraulic aperture of the entire specimen, resulting in a wide range of values. Measured aperture sizes were used to evaluate possible microannulus repair by estimating the penetration of cementitious materials. The data showed that the repair using cementitious materials is unlikely to be effective for microannuli with a hydraulic aperture

Sustained casing pressure (SCP) caused by tubing leakage is mostly considered as the dangerous situation in gas wells, which is more likely to pose a serious threat to well integrity and environmental protection. In order to assess the downhole risk in early time and further provide maintenance strategies to optimize well performance, it is necessary to diagnose the source of downhole leakage accurately. This paper presents a pressure-balance-based approach for capturing two types of dynamic annulus pressure behaviors in a gas well with SCP caused by tubing leakage at different well depths. The approach includes models that take into account the influence of temperature and pressure distributions of tubing and annulus fluid, which are used to determine tubing leakage points. In addition, such an approach involves the calculation of maximum annulus pressure at the wellhead in a gas well with SCP under four main cases, representing the effects of the leakage location, bottom hole pressure, annulus liquid level and gas production rate on wellhead pressure. Afterwards, an integrated diagnostic testing system has been developed to monitor the synthetic state of annulus fluid and liquid level parameters, ultimately identifying the source of SCP correctly. In contrast to previous works, leakage diagnostic testing can be performed from an offshore platform, and it meets the requirements of offshore field testing and works without a shut-in condition, which is capable of overcoming limitations of downhole detection. A case study focused on an offshore gas well with SCP is presented to illustrate the feasibility of the proposed approach, and also to demonstrate that leakage diagnosis contributes to the mechanism investigation of SCP, as well as the design improvement of gas wells integrity.

In high-temperature and high-pressure (HPHT) gas wells, the wellhead growth caused by temperature and pressure effects during production might damage the well integrity. A calculation model of the wellhead growth produced by temperature and pressure effects was built. For the case well, the maximum pressures of annulus A, B and C are 64 MPa, 48 MPa and 38 MPa, respectively. The maximum production and intervention time are 114.5 × 10 4 m 3 /d and 540 d, respectively. Based on the calculation process, the maximum wellhead growth is 412.7 mm. The axial load caused by the multiple annuli pressure is second only to that caused by the casing axial temperature difference. Wellhead growth increases with the annulus fluid thermal expansion coefficient and decreases with the annulus fluid isothermal compression coefficient. The increasing annulus temperature difference might aggravate the effect of annulus fluid thermal properties on the wellhead growth. Selecting the casing with greater wall thickness and lower thermal expansion coefficient can reduce the wellhead growth. The annulus width has little effect on the wellhead growth while the annulus length will significantly change the wellhead growth. The wellbore multiple annuli pressure can increase the wellhead growth prominently. The annulus pressure management shall be introduced into the production. Optimizing the well structure and production plan and installing the wellhead monitoring equipment contribute to mitigating the wellhead growth.

Optimum production from a hydrocarbon field takes place when technical parameters are optimized with respect to the operational and economic constraints. Well control parameters have an important role in making decisions for choosing efficient production scenario in a reservoir. Among the economical constraints cost of drilling and completion of wells, transportation and refinery costs and price of oil and gas can be named. In this paper, using single well model, the design of experiments and multi criteria decision making, determination of optimum production scenario based on a sector of South Pars gas field is addressed. Flow rate, well spacing, minimum wellhead pressure, production string size, deviation of wells and type of stimulation are decision parameters that are considered in this study. Economic indices chosen for economic analysis are net present value, internal rate of return and plateau time. First using the design of experiments and response surface methodology, proxy models are generated to predict economic indices for production scenarios and after validation of them, they are used for economic analysis and choosing the best scenario based on multi-criteria decision making.

Numerous empirical correlation models for predicting wellhead flow rates have been proposed. Here we apply a recently developed model based upon extensive data from the Ghawar Field (Saudi Arabia) to the Pazanan 1 retrograde gas-condensate field (Aghajari, Iran). A firefly optimization algorithm is applied to select the optimum coefficient values for that model by minimizing the mean square error between measured and predicted gas flow rates from a wellhead-test data set. The input data to calculate gas flow rate includes choke diameter, gas specific gravity, flowing fluid temperature, upstream and downstream pressure. The models prediction accuracy depends upon the coefficient values applied in its formula. The firefly optimization model was tested with various sensitivity cases applying different values to the key control variables γ and N (number of fireflies in the population). Optimum results in terms of minimum mean square error and rapid convergence was achieved with the control variable values γ = 2 and N = 40. The optimum case achieved with low error values and a level of accuracy that is significantly better than the predictions for dataset using the coefficient values applied to the Ghawar field, suggesting that such model coefficients need to be optimized on a field-by-field basis.

The accuracy control of the production pressure difference is of great importance to the efficient development of marine gas hydrates through depressurization. But from the field trial production, the existing control method of bottom hole pressure is difficult to achieve the expected depressurization target. To this end, a transient gas-liquid two-phase flow model in marine gas hydrate production system was established, which considers the coupling interactions of the wellbore, the formation and the downhole electric submersible pump (ESP). Besides, an automatic control method of production pressure differential was proposed through real-time optimization of the pump displacement. Using the model, a series of numerical simulations were performed to study the multiphase flow rules in the production well. The results indicated the depressurization process could be divided into four stages based on the characteristics of gas-liquid flow in different pipelines. During the depressurization, the liquid level in the well exhibited a trend of first falling and then rising, and may eventually reach the wellhead for continuous drainage. In addition, sensitivity analysis showed that the smaller the pipe diameter, the higher the gas-liquid separation efficiency, and the greater the possibility of continuous drainage from the gas production pipeline. As the result, it was verified that the proposed model and method can achieve the expected depressurization well, which will provide useful references for the production design during the development of marine natural gas hydrate resources.

As industry moves toward the production of oil and gas resources in deep offshore environments, the prospective formation of natural gas hydrates under low temperature, high-pressure conditions poses an increasing risk of pipeline blockage. Successful management of this risk requires a precise forecast of the hydrate growth rate. Such predictions should incorporate quantitative descriptions of both deterministic and probabilistic hydrate phenomena. In this work, we present a first step towards such a quantitative risk assessment for systems that form hydrate slurries, based on a consideration of the stochastic nature of hydrate formation. Our framework introduces a new approach to risk assessment, by coupling a laboratory-derived probabilistic nucleation model with existing deterministic calculations for hydrate slurry viscosification. This new approach is used to extend a previously-described hydrate risk algorithm, the Hydrate Flow Assurance Simulation Tool (HyFAST), which enables the rapid assessment of hydrate slurry viscosification using the most advanced models available. Importantly, while the previous version of HyFAST was constrained to calculations in flowloop and autoclave geometries, for which it is sufficient to consider a single volume element, the new version of the HyFAST algorithm allows calculations for flowlines wherein a series of multiple volume elements are considered. The advanced hydrate formation models within this algorithm allow identification of critically important hydrate formation scenarios, and may serve as a screening tool for cases that then require study within rigorous hydrodynamic packages such as OLGA® or LedaFlow® to examine behaviour during key transient events. By coupling the outputs of our predictive algorithm and quantitative risk framework, we demonstrate a new capability to assess what constitutes an acceptable level of hydrate formation. We use this algorithm in a series of case studies that compare the effectiveness of common hydrate mitigation strategies over the life of a reservoir, including the optimization of a wellhead choke opening for both production rate and hydrate blockage risk.

During nitrogen drilling in tight sandstone reservoirs, the multifunctional four-way often suffers severe erosion damage after withstanding the erosion of sand and gas over an extended period of time. Such damage may have serious consequences for its functioning. In this study, an experiment was conducted on the erosion of a wellhead device used in nitrogen drilling. The conditions used in the experiment were also used as inputs for numerical simulation of the erosion pattern. The results obtained from the numerical simulation were then compared to those obtained in the experiment in order to determine the reliability of numerical simulation for analysis of erosion pattern in nitrogen drilling. The results of the simulation, scaled down by a factor of 10, were consistent with the results of the experiment. Further, the relative error between the sets of results was less than 5% (the overall mean error is 1.11%) for gas–solid two-phase erosion and flow models implemented using FLUENT software. The results verify that numerical simulation is reliable and can be used to study the erosion of wellhead equipment in nitrogen drilling. This will be of great significance in alleviating the safety problems associated with well control in nitrogen drilling.

Gas migration has long been recognized as one of the most difficult problems in the oil and gas industry. Due to the complicated interactions between temperature, pressure, and cement hydration reaction, the temperature and pressure in a deep-water environment makes gas migration in cement a complicated process, by effecting the driving forces and channels of gas migration. Accordingly, a transient prediction model for cement temperature and pressure based on cement hydration kinetics was established in this study. Using this model, cement microstructure under different temperatures and pressures was studied. In addition, a mathematical model for gas seepage through the microstructure of a cement sheath was also suggested. The proposed models were validated by comparing the results obtained from those of experimental studies from the literature, where a good agreement was obtained. Furthermore, numerical simulations were conducted by applying the proposed models to a simulation well. The simulation results demonstrated that the microstructure of the cement sheath varied with time and space under the effect of temperature and pressure. The cement pressure first decreased with the deepening of cement hydration, and then increased as a result of gas migration. In addition, the gas migration resulted in a sustained casing pressure at the wellhead as high as 14.26 MPa. This would pose a threat to safety and subsequent oil and gas production.

Understanding the nature of fluid flow through fractured wellbore cement is fundamental for evaluating the leakage potential and risk assessments of leaky wellbores. In this study, the conditions that require considering visco-inertial flow for describing the gas flow through wellbore cement fractures were investigated. Nitrogen gas flow tests were conducted on fractured cement samples under varying pressure conditions and flow rates, covering both viscous and visco-inertial flow regimes. The data substantially deviated from Darcy's law at higher flowrates and were well-fit to Forchheimer's equation for visco-inertial flow. The inertial coefficient and critical Reynolds number were expressed as a function of the hydraulic aperture. The empirical function obtained from the experiments was used as an input to numerical simulations which showed the significant role of visco-inertial flow in wellhead pressure build-up and leakage rates, and demonstrated the importance of visco-inertial flow when modeling gas flow through wellbore cement fractures.

Venturi is one of the most commonly used flowmeters for measuring gas-liquid flow at the natural gas wellhead. A better understanding of the flow mechanism and the causes for pressure drop is necessary for the establishment of the measurement model. In this study, a one-dimensional pressure drop model between the two pressure taps of Venturi has been proposed for vertical annular-mist flow. The relations between the liquid film, entrainment rate, void fraction, and velocity slip have been revealed when the annular flow went through Venturi. We consider the gas acceleration in the throat of Venturi. The proportions of various pressure drops are given. The experimental results show that the relative errors of the pressure drop have a confidence probability of 98.5% within 10%. The predicted results are also in good agreement with the on-site data. It proves that the new pressure drop model has good performance.

This study proposes a transient gas-liquid-solid multiphase flow model for gas kick during MPD, considering the effect of dynamic wellhead back-pressure, temperature field, and velocity relation of different phases. Based on this model, the gas kick control strategies and outflow response characteristics during MPD are thoroughly investigated. The simulated results reveal that, with the upward migration and expansion of the invading gas, the hydrostatic pressure and frictional pressure in the annulus changes accordingly, resulting in a non-linear relationship between the wellbore back-pressure and the bottom-hole pressure. Moreover, the effects of an under-balance pressure at the bottom hole, the pressure balance relationship between the formation and the bottom hole, the kick detection level, the well depth on the wellhead back-pressure control and the response behaviors of the outlet flow rate are discussed. The results of this investigation can provide engineering guidance for MPD to address the issue of gas kick.

The co-existence of gas, water, and monoethylene glycol (MEG) is common in produced fluids of high-pressure gas wells. Accurate predictions on the temperature changes during the choking process are essential for the design and operation of the choke valve. This paper presents an efficient multiphase isenthalpic flash method based on the cubic-plus-association equation of state (CPA EOS) to calculate the choke temperatures. In comparison with the traditional isenthalpic flash algorithm, this new method accounts for the self- and cross-association between polar water and MEG molecules, yielding more accurate enthalpy calculation results and multiphase component distributions for fluids containing water and MEG. The proposed model is validated by field test data with pressures from 8.68 MPa to 119.3 MPa. The average absolute deviations between the calculated choke temperatures and measured values are less than 1.6 °C even for vapor-liquid-aqueous three-phase mixtures at various pressures. Moreover, case studies show that accounting for the association between polar water/MEG molecules contributes to accurate predictions on choke temperatures. At high pressures, the CPA EOS tends to give higher choke temperatures in comparison with those calculated based on the traditional SRK-Peneloux EOS. In contrast, the CPA EOS tends to yield lower temperatures at low pressures.

Unacceptable errors resulted from utilizing the current correlations for investigating the behavior of sub-critical two-phase flow regime through wellhead chokes of south Iranian gas condensate reservoirs led us toward establishing a new Gilbert-type correlation capable of fitting the production data with minimum errors. The proposed model, which is a modification of Nasriani and Kalantariasl model, is able to predict the high flow rates of gas condensate wells under sub-critical conditions particularly in case of large choke sizes. In order to validate the new correlation, Genetic Algorithm and non-linear regression analysis methods are implemented to sixty seven production datasets of fifteen wells with large wellhead choke sizes (40/64–192/64 inch) gathered from 10 different fields. Then the proposed correlation in addition to two other models (1.Osman and Dokla 2. Nasriani and Kalantariasl) are conducted to each choke size to investigate the applicability of the new formula in comparison with the existing ones. Moreover, in order to evaluate the new model in other field data, 39 data points gathered from gas-condensate wells of Fars province of Iran are exposed to the proposed model, and the two other models. Finally, the main form of the new correlation is applied to dataset of each choke size. The results indicate that the non-linear regression technique is more accurate than Genetic algorithm in fitting the data to the proposed method. Furthermore, the new correlation has the minimum errors in comparison to other methods in both investigated areas. Finally, according to statistical error analysis for each choke size, the ability of the proposed correlation to predict gas flow rates of fluids passing through the wellhead chokes of gas-condensate wells under sub-critical conditions is found to be highly improved when applied to individual choke sizes.

This paper describes a new downhole multistage choke technology for lowering the wellbore pressure and temperature profile of a high-pressure and high-temperature (HPHT) gas well. With the nodal system analysis of a gas well, the wellbore pressure and temperature distribution model of a downhole multistage throttle was established when coupling the throttling pressure and temperature dropping model. An example of a HPHT gas well was analyzed and also the choke hole diameters, numbers and positions of the downhole chokes were optimized according to the presets of the wellhead pressure, temperature and acceptable sustained casing pressure (SCP) in the A annulus. The results show that when adopting two-stage downhole throttling, the wellhead tubing pressure, average wellbore temperature, and the wellhead casing pressure in the A annulus have been decreased by 64.4%, 37.8%, and 43.6%, respectively, compared to the case with the surface choke technology. Therefore, using multi-stage throttling technology in HPHT gas wells can reduce wellhead pressure and wellbore temperature significantly, which can effectively lower the risk of SCP, ensure the integrity and security of wellbore and also greatly reduce the platform space for fixed offshore gas wells.

Two-phase flow through chokes is common in oil industry. Wellhead chokes regulate and stabilize flow rate to prevent reservoir pressure declining, water coning and protecting downstream facilities against production flocculation. Choke liquid rate prediction is a basic requirement in production scheme and choke design. In this study, for the first time a least square support vector machine (LSSVM) model is developed for predicting liquid flow rate in two-phase flow through wellhead chokes. Particle swarm optimization (PSO) is applied to optimize tuning parameters of LSSVM model. Model inputs include choke upstream pressure, gas liquid ratio (GLR) and choke size which are surface measurable variables. Calculated flow rates from PSO-LSSVM model are excellently consistent with actual measured rates. Moreover, comparison between this model and related empirical correlations show accuracy and superiority of the model. Results of this work indicate PSO-LSSVM model is a powerful technique for predicting liquid rate of chokes in oil industry.

The physical properties of Sichuan tight sandstone formations include low porosity and low permeability. Fortunately, micro-fractures are well developed in this area, and the development of a reservoir is thus possible. Acidification can repair reservoir damage and improve single-well production; however, gas well production can change after acidizing: some wells improve, while others decline. After many studies, the flowback system after acidification has been shown to play an important role in determining the acidizing effect. Therefore, optimizing the flowback system after acidification can significantly influence the results of acidizing. A series of velocity sensitivity experiments have been performed, and their results show that the velocity sensitivity is high. Based on fluid mechanics principles, an optimization model of the acid flowback is constructed using experimental results; as a result, the relationship between the pressure drop in the wellhead and the choke size can be calculated, and a reasonable choke during the process of acid flowback can be determined using the methods described in this paper. The results are of great significance in optimizing the flowback system after acidification and also in enhancing the gas production of single wells.

Induced flow after completion is one of the challenges that hinder the development efficiency for depleted offshore gas reservoirs. Coiled tubing (CT) gas injection has many advantages in inducing the wells to self-flow. The critical conditions of induced self-flow are analyzed. And the pressure distribution in the annulus between the oil tubing and CT is calculated by numerical modeling based on gas–liquid two-phase flow theories. The effects of gas injection depth, injection rate, CT size, wellhead back pressure, and well deviation angle on the results of induced self-flow are investigated. Numerical modeling results indicate that the pressure drop caused by gas injection decreases significantly as the injection depth decreases, and as the wellhead back pressure and the well deviation angle (especially for high angles, >60°) increases. Within the range of injection rates commonly used for CT gas injection, CT size and injection rate show little influence on the pressure drop. Therefore, injection depth and wellhead back pressure are key factors controlling the results of the induced flow treatment. For horizontal wells and high deviated wells, it is better to use a deeper injection depth and/or lower wellhead back pressure, which benefits the successful induced flow.

CO2 flooding can improve the oil recovery factor more effectively compared with conventional water flooding; however, a problem occurs when H2S is produced more rapidly due to the influence of sulphate-reducing bacteria (SRB). On the basis of the ecological features of sulphate-reducing bacteria (SRB) and the effects of CO2 flooding on the properties of the production fluid, we analysed the ecological features of sulphate-reducing bacteria in a CO2 flooding gathering environment through research on the content change of SRB, H2S, and the full components of the associated gas in the process of “the wellhead→ the metering station→ the transfer station→ the joint station→ the water injection station→ water injection well→ the wellhead”. The analysis results indicate that the temperature, pH value, and nutritional condition in the CO2 flooding gathering system are generally suitable for the growth and metabolism of sulphate-reducing bacteria (SRB). Therefore, H2S is produced because sulphate-reducing bacteria can easily breed in the CO2 gathering system.

Well production rate is a major factor for simulation of commingled gas wells. It is the base of computations of well flowing pressure, pressure drop, well performance, flow regime, liquid holdup, reservoir performance, material balance and average reservoir pressure. Typically, well flow rate is measured using flow meters like orifice, but in some wells flow rates remain unknown due to shortage of flow meters and commingled production. In this paper, well flow splitting of a gas-condensate field with two platforms is studied. Each platform consists of ten wells and wellhead pressure is controlled by a choke valve. Total flow rate of platforms mixed production is measured after sending their production to refinery. The proposed methodology for dividing total flow between wells consists of choke modeling using test separator data and flow modeling in the wells. Choke models include mechanistic and Ashford and Pierce as theoretical models and Gilbert, Ros and Pilehvari as empirical models. In most investigations choke size is represented with length unit such as inches but in this work, flow is calculated on the base of choke opening percent and choke size as a function of choke opening percent is obtained. Chokes are modeled with upstream temperature, upstream pressure and downstream pressure. Rich gas flow calculations with the proposed method were compared with reported total flow of platforms and showed mean absolute percentage error of 3.2% for mechanistic model as the best of studied models. This error can cause 0.5% error in calculated well flowing pressure. Sensitivity analysis on operation parameters showed that since the gas-condensate field is lean, gas flow rate is the major phase for modeling and uncertainty of gas-condensate ratio and changing specific gravity and molecular weight of condensate with time do not have considerable effect on well flow rate calculations.

In order to analyze riser stress and deformation in its installation, a static analysis model and equation have been established and the equation is solved by the finite difference method. In this model, the riser is regarded as a beam suspended in the floating drilling platform (ship) and subjected to both axial and lateral forces. In order to connect the Blowout Preventer Stack (BOPS) and the subsea wellhead, the floating drilling platform (ship) needs to move to drag the riser and BOPS. However, during the movement of floating drilling platform (ship), the riser stress distribution will change. The total stress variation with the movement speed of floating drilling platform (ship) has been figured out. Because riser deformation could be affected by several operational factors and environmental factors, the deformation variation with water depth, riser size, BOPS weight, sea surface wind velocity, sea surface tide velocity, wave height and wave period are discussed. Results show that there is a maximum movement speed of floating drilling platform (ship). If the actual speed is greater than the maximum value, the riser material will be in danger of damage. The riser deformation will increase as water depth, sea surface wind velocity and sea tide velocity increase and will decrease as riser size and BOPS weight increase. However, wave height and wave period almost have no impact on riser deformation. Since the analysis model established is a static one, the dynamic problem is not discussed in this paper.

One of the main problems that occurs in the gas reservoirs is related to the hydrate formation while producing from a well, either in production strings or lines. Effective parameters which lead to hydrate formations are: high pressure in strings, low wellhead temperature together with water presence; and hence, the high possibility of having this phenomenon in the reservoirs is quite obvious for the gas wells. Hydrate formation in production lines and facilities will also lead to different impediments such as: complete or partial closure in production lines and heat exchangers, erosion of the equipment, pressure reduction, and etc. In this research, the conditions of hydrate formation, using the experimental data from one the Iranian sour gas field have been investigated. In addition, the inhibition effect of methanol on the hydrate-forming conditions has been explored. Finally, the experimental data have been compared with model and the effect of CO 2 injection on hydrate phase diagram was evaluated using the presented model.

The wax deposition from the gas condensate in South Pars gas processing plant causes a number of severe problems. These problems include: (1) deposits form on the reboiler tubes of stabilizer column and tend to reduce its duty (2) forcing periodic shut-down and removal of deposits (3) interrupting normal processing operations. An understanding of deposition, nature and propensity is necessary to mitigate the mentioned problems. In this work, the multi solid phase model is used to predict the wax precipitation from gas condensate fluid. For five different reservoir fluids, several methods were investigated to split the heavy hydrocarbon fraction into pseudo fractions. The results show that the Al-Meshari method is the most accurate one. Also, a set of consistent correlations were used to calculate the critical points, fusion properties and the acentric factor of the single carbon number groups in the extended composition. Finally the best methods for predicting the wax formation are selected and used to predict the wax formation in the sea line of South Pars gas processing plant. The modeling shows that wax precipitation starts at 293 K and 86 bar. At this pressure and temperature the pipeline is 94 km away from the wellhead.

Choke valves are critical elements in gas production facilities. Malfunction or failure of a choke valve can seriously affect safety, the environment and production rates. Choke is a device installed at wellhead or down hole to control the flow rate for maintaining sufficient back pressure to prevent formation damage, to prevent water/gas coning, to stabilize the flow rate and to produce the reservoir at the most efficient possible rate. In this work a simple-to-use method is developed to estimate the choke flow coefficient for natural gas subsonic flow through orifice-type chokes as a function of Reynolds number and the ratio of choke diameter to pipe diameter. The results can be used in follow-up calculations for rapid estimating gas passage through a choke under subsonic flow conditions. Estimations are found to be in excellent agreement with reported data in the literature with average absolute deviation being less than 0.4%.

Distributed temperature sensing or DTS is gaining increasing popularity because of its potential to generate flow profiles over completed intervals. In fact, several studies have reported successful reproduction of field data, obtained with conventional production logs, in both vertical and deviated wells. One input that enters into typical DTS calculations is the total flow rate at surface. In absence of dedicated flowmetering, uncertainty normally creeps into assigned well rates. This study provides a methodology wherein both the total and individual layer rates can be computed independently with DTS, completion, tubular, and other related data. To do the entire suite of calculations, a wellbore model handling steady fluid flow and unsteady-state heat transfer estimates a production rate, given wellhead pressure and temperature. The same model is then used to compute the flow profile based on measured DTS data across the producing intervals. The model rigorously accounts for various thermal properties of the fluid and the formation, including Joule–Thompson (JT) heating or cooling. Examples from both gas and oil wells are shown to illustrate the application of the proposed methodology. Good correspondence between the measured and calculated results demonstrates the robustness of the proposed method.

Casing string is rotated by torque from wellhead during casing drilling. The method to determine casing torsion status under various torques in casing drilling was discussed. There are three different torsion statuses under different torques, including elastic torsion, elastoplastic torsion and plastic torsion. The residual stress distribution was also discussed under different torques. The average residual stress under elastoplastic and plastic torsion status was calculated respectively; The modified casing collapse strength formula was derived considering the effect of residual stress. The analysis of calculation results indicates that the residual stress caused the collapse strength to decrease 0.033% under elastoplastic torsion, and effects of residual stress on casing strength can be neglected when there is no geometry shape changes in the casing.