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Riser will bend and deform in deep-water and ultra-deep water drilling, which may affect the dynamic characteristics of the drill-string. The analysis of drill-string dynamic characteristics is very difficult due to its super slenderness ratio. As the drill-string rotates in a curved narrow wellbore, the geometric nonlinearity and contact nonlinearity must be considered. In this study, a new method is proposed to analyze the drill-string dynamics considering the influence of riser deformation. The configuration of riser, based on different sea current velocities, is calculated to form a quasi-dynamic well trajectory combining with the fixed wellbore under mudline. In order to solve the dynamic problem of an extra-long drill-string model, the node iteration method is used to judge whether contact occurs at each node, and the Newmark method is used to calculate the spatial configuration of the drill-string at each time step. A program is successfully developed to analyze the dynamic characteristics of the drill-string in a deformed riser. The simulation results show that the deformation of the riser caused by ocean current has a great influence on the lateral vibration of the upper drill-string, and relatively little effect on the bottom-hole assembly. The contact and collision force near subsea wellhead is so large that may result in eccentric wear and leakage of the nearby riser.

Natural gas hydrates are expected to be one of the most important unconventional energy resources in the future. China is accelerating its research and trial exploitation of hydrates in the South China Sea, which is where most of China's gas hydrate reservoirs are located. Because it represents a prospective alternative energy source, it is necessary to use the energy return on investment method to evaluate production efficiency. The results show that the average standard energy return on investment is 0.74, the energy return on investment within the boundary from wellhead to processing is 0.58, and the energy return on investment within the boundary from well to utilization is 0.56. The negative net energy suggests that natural gas hydrate is not presently a favourable choice to replace conventional energy sources; thus, the large-scale development of natural gas hydrate requires further technological development. Sensitivity analysis shows that to acquire a strong positive energy return on investment, technological developments must be accompanied by simultaneous increases in ultimate gas recovery and the gas-to-water ratio. Moreover, the choice of proper production methods has an important influence on energy return on investment and should be based on the knowledge of physical properties gained through sufficient geological surveys.

Drill string will sustain large uplift force during the shut-in period after gas overflow in an ultra-deep well, and in serious case, it will run out of the wellhead. A calculation model of uplift force was established to analyze dynamic change characteristics of the uplift force of drill string during the shut-in period, and then a management procedure for the uplift risk during the shut-in period after gas overflow in the ultra-deep well was formed. Cross section method and pressure area method were used to analyze the force on drill string after shut-in of well, it was found that the source of uplift force was the “fictitious force” caused by the hydrostatic pressure in the well. When the fictitious force is in the opposite direction to the gravity, it is the uplift force. By adopting the theory of annular multiphase flow, considering the effects of wellbore afterflow and gas slippage, the dynamic change of the pressure and fluid in the wellbore and the uplift force of drill string during the shut-in period were analyzed. The magnitude and direction of uplift force are related to the length of drill string in the wellbore and shut-in time, and there is the risk of uplift of drill string when the length of drill string in the wellbore is smaller than the critical drill string length or the shut in time exceeds the critical shut in time. A set of treatment method and process to prevent the uplift of drill string is advanced during the shut-in period after overflow in the ultra-deep well, which makes the risk management of the drill string uplift in the ultra-deep well more rigorous and scientific. Key words: ultra-deep well, drilling, overflow, shut-in, drill string, uplift force, axial load

Hydrate formation poses a risk to deepwater drilling operations. Most current studies on the hydrate formation and its impact on deepwater drilling operations have focused on the risk associated with hydrates inside the wellbore. Few researchers have studied the risk of hydrate formation outside the wellbore, and the risks to deepwater drilling are still unclear. In the South China Sea, there have been several events of hydrate growth on the outer surfaces of the subsea wellhead. The mechanisms of hydrate growth on the outer surface of the subsea wellhead are analyzed, and the gas source is predicted by analyzing the logging data of the adjacent wells. A model for the wellhead stability is developed, and the impacts of hydrate formation on the stability of the subsea wellhead are analyzed. The gas source, temperature, pressure, solid surface roughness, and relative static subsea environment are found to be the key factors in the formation of hydrate in the marine environment. The risk of hydrate formation to wellhead stability is subtle, but to blowout preventer (BOP) could be significant. Hydrates may cause BOP control failure in which the BOP could not be closed in the event of emergency; hydrate formation between the BOP and the wellhead may cause BOP not to be separated from the bottom of the wellhead. A tool was designed for controlling the formation of hydrates, with particular tilt angle and surface roughness. Because the appropriate tilt angle can divert the gas bubbles to avoid the hydrate formations at the wellhead. The designed hydrate control tool successfully mitigates the risks to drilling operations.

Currently, the analysis of Sustained-Casing-Pressure (SCP) tests is limited because some researchers' simulations did not take the effect of gas migration in mud into account and their models were based on Newtonian fluids. This is not consistent with the actual field situations that gas migrates in non-Newtonian fluids. In addition, the yield stress effect was also not taken into account. To ensure the operators a realistic and accurate diagnostic testing for the SCP problem, the improvements of mathematical models in SCP problem are of great significance. In this study, by considering the correlation between gas velocity and drag coefficient, a new formula of gas migration velocity in stagnant non-Newtonian fluids was established. Moreover, the yield stress effect was incorporated in the new model. The validations of field data demonstrate that the new model has the credence to the field work. Furthermore, in this study, the effect of gas migration on SCP problem was paid attention seriously based on new model. To demonstrate the importance of gas migration effect, the analysis of variance (ANOVA) were employed to find out the values of mud properties (flow behavior index, yield stress, length of mud, consistency index) that can most significantly influence the wellhead pressure. Then these most influential parameters were utilized in both the new model (with gas migration effect) and the previous model (without gas migration effect) to conduct the comparison. The comparison result indicate that the value of mud compressibility and the value of cement permeability got by the new model are higher than those by the previous model, and the value of initial gas chamber size got by the new model is lower than that by the previous model. These stress explicitly the necessity and significance of considering gas migration effect and considering the non-Newtonian effect on SCP problem, which should not be neglected. The developed models in this research offer significant insights into the SCP problem, which turns out to be powerful in the application of analyzing the SCP problem. This work can lay the theoretical basis to assist operators in diagnostic testing of wells with SCP problem accurately.

Industry experience has shown that downhole tubing leakage is the most challenging issue resulting in sustained casing pressure in natural gas production wells. This article presents a novel tool based on pressure difference and probability distribution for predicting the tubing leakage location for an offshore gas production well with sustained casing pressure. Combined with the formation information, well structure, annular fluid level and dynamic production parameters of a gas well, the model of pressure difference between tubing and production casing annulus is established. However, these pressure-based predictions suffer from various sources of uncertainties, such as the variations in reservoir conditions, and measurement errors. Bayesian inference is introduced to handle these uncertainties in leakage location forecasting effectively. Dynamic confidence intervals under two kinds calculation modes are applied to calculate the leakage depth within a certain range. The probabilistic distribution of leakage location is statistically predicted under different wellhead pressure difference using Monte Carlo simulation. A case study on a specific offshore gas well with the field data is presented to illustrate the feasibility of the proposed method and to demonstrate that the downhole tubing leakage location prediction contributes to the safety and integrity management of offshore production wells in an economical and convenient way.

In light of the direct entry of surface water by inundation during floods and extreme rainfall events into riverbank filtration (RBF) wells and the consequent risk of contamination, this study discusses the state of the art of sealing the borehole annulus and well headworks in some developing countries exemplified by northern India in context to established guidelines and standards. Accordingly a market survey was conducted and a concept was developed to construct watertight wellhead elements and a flood-proof well chamber. The concept was implemented through the fabrication of the major components of a watertight wellhead in India and the subsequent construction of watertight headworks and a flood-proof chamber for a RBF well in Srinagar (Uttarakhand, India). The study showed that water wells at risk of flooding in general can be made flood-proof. A novel concept of deliberately flooding the well chamber was tested and proved successful. Although the fabrication enterprises and suppliers of well construction material in India currently do not produce non-standardised or special purpose well components, experience from the current study shows that local small-medium enterprises engaged in the unorganized metal working sector possess the technical competence to fabricate some of the major components but in limited numbers. The familiarisation of water supply practitioners and the well construction industry in India on the need and measures to flood-proof wells must be continued through information and education campaigns.

Electric submersible pump (ESP) has become an important mechanical oil equipment in the digital oil field, and it is necessary to perform the condition monitoring and fault diagnosis on the ESP system. An on-line technique is proposed based on the electric parameters and production parameters. To realize the fault diagnosis of the ESP in the ground, the algorithms are designed by feature extraction, and the algorithms combine the electric parameters in the electric cabinet with the production parameters, which are separated by a newly designed gas–liquid two-phase flow meter. Meanwhile, electrical parameters are the main ones and production parameters are the auxiliary ones. The parameter features are extracted from different faults by digital signal processing, and the study accurately monitors nine typical operating conditions of the faults. Importantly, the method enormously reduces the impact on the sensors in the down hole, and the test data show that the method has the advantages of low cost and high efficiency.

During the execution of technological operations such as multiple pressure relief or foam separation during well injection, a gas column can form at the wellhead in the annular space, leading to annular pressure buildup (APB). Based on the theory of heat transfer, a model was proposed for calculating the wellbore heat transfer during production. Taking into account the expansion and compression of the fluid, changes in the wellhead volume, the thermodynamic characteristics of the liquid, and the equation of state of the gas, APB calculations were performed. Based on these parameters, the influence of the gas column height on APB was evaluated. The results of the studies show that the coefficients of expansion and compressibility in the annulus depend on density, pressure and temperature: the higher the productivity of the gas well, the higher the temperature and pressure in the annulus; the greater the height of the gas column, the lower the pressure at the wellhead. For a well with a productivity of 30· 104 m3/day and gas column height of 70 m in the annulus, the APB is reduced to atmospheric pressure. Studies of the model for calculating APB of the annular trapped gas provide a theoretical basis for developing optimal technological parameters for the operation of gas wells.

This paper presents surface movement (uplift and subsidence) analysis around three CO2 injection wells at In Salah, Algeria. Analysis of surface movement is based on the InSAR data acquired throughout the injection period from 2004 to 2011. This paper focuses on the detail surface deformation patterns for all three injectors throughout the injection period, and eventually correlates such patterns to the CO2 injection history. Surface uplift has a higher rate in the beginning of the injection period but levels off later on and reaches a final uplift of about 15–22 mm above different wells. We will explore whether surface movement data can reveal signatures of injection regime (i.e. matrix and fracture injections) in the reservoir. Surface movement, for a few selected points at different distances from the wellhead, and the injection pressure are plotted versus time to explore their relationship. Analysis of the plots show that surface subsidence coincide with fracture injection for some points and at certain times whereas it coincides with matrix injection for others. We also tried to map out possible time delay between injection shut-in and surface subsidence. It is learned that quantification of such a delay as well as monitoring the response of surface to fracturing in the reservoir requires high resolution surface movement data. This study shows the potential of satellite survey for monitoring the injection regime and behavior of reservoir and overburden.

This paper describes oil spill stakeholder engagement in a recent comparative risk assessment (CRA) project that examined the tradeoffs associated with a hypothetical offshore well blowout in the Gulf of Mexico, with a specific focus on subsea dispersant injection (SSDI) at the wellhead. SSDI is a new technology deployed during the Deepwater Horizon (DWH) oil spill response. Oil spill stakeholders include decision makers, who will consider whether to integrate SSDI into future tradeoff decisions. This CRA considered the tradeoffs associated with three sets of response strategies: (1) no intervention; (2) mechanical recovery, in-situ burning, and surface dispersants; and, (3) SSDI in addition to responses in (2). For context, the paper begins with a historical review of U.S. policy and engagement with oil spill stakeholders regarding dispersants. Stakeholder activities throughout the project involved decision-maker representatives and their advisors to inform the approach and consider CRA utility in future oil spill preparedness.

None of the various published models used to predict oil production rates through wellhead chokes from fluid composition and pressures can be considered as a universal model for all regions. Here, a model is provided to predict liquid production-flow rates for the Reshadat oil field offshore southwest Iran, applying a customized genetic optimization algorithm (GA) and standard Excel Solver non-linear and evolutionary optimization algorithms. The dataset of 182 records of wellhead choke measurements spans liquid flow rates from

Drilling risers are the critical connection of subsea wellhead and the floating drilling unit. With exploration and development of oil and gas resources moving into deepwater, drilling riser operations have been characterized with high safety risk and occurrence rate of accidents causing high drilling downtime and drilling cost. In the present study, a Fuzzy Petri Net (FPN) methodology is proposed to evaluate the comprehensive risk of deepwater drilling risers. A risk index evaluation system was established based on analyses of drilling riser accidents and identification of risk factors, and the AHP-EM method was used to determine the weights of them. A 9-tuple set was defined to model drilling riser risks according to the FPN theories, and by using the fuzzy reasoning algorithm, risk values of risk factors at different levels and the integrated system were gained by iteration of state matrix. A specific case study of deepwater drilling risers of NANHAI-8 drilling unit in Liuhua oilfield in South China Sea is presented to illustrate the application of proposed approach, and some suggestions drawn from the investigation are presented to further mitigate the risk of drilling riser operations. The case study showed that FPN is a practical and reliable method in comprehensive risk evaluation of deepwater drilling riser system.

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.

Water injection wells often develop casing leaks that result in crossflow between two formations. The crossflow can be upward or downward depending on the respective location of each formation and the gravitation hydrostatic column between the formations. Traditionally, crossflow rates are measured by running production logs (flowmeter); a process that require well intervention. Such intervention in a well with compromised downhole integrity is not preferred as it incur additional cost and exposes the oilfield operator to possible mechanical risks such as stuck tools. In this work, we present a numerical method to predict crossflow rates without such intervention. The method requires readily available input from the water injection that includes injection flow rates and pressures, in addition, to shut-in well data. The workflow developed in this study includes nodal analysis and well performance modeling. A water injection well (Well-XYZ) was selected to validate the developed workflow as a case study in this paper. Well-XYZ has an upward crossflow that resulted from a downhole leak. The numerical method starts with building a well performance model before the leak develops. The injection data (pressure and flow rates) before leak development are used for this model. Second, a well with the same physical dimensions of Well-XYZ is imagined and modeled as a producing well from the downhole formation to the leak point. The shut-in well data of Well-XYZ are used to build the production well model. Third, we choose the leak point as the system node and obtain its pressure either by direct measurement or through calculation. Once the system node pressure is obtained, it is inputted as the wellhead producing pressure of the imagined well and its production rate will be the crossflow rate. The results of this method were tested by running a production log on Well-XYZ. The results of the production log showed that the method was able to accurately predict the crossflow rate with a less than 2% error.

The Lower Cambrian Longwangmiao dolomite gas reservoirs in the Sichuan Basin are characterized by well-developed natural micro-fractures and dissolved pores and cavities. Due to the strong heterogeneity of reservoirs and the serious damage of drilling and completion fluids, acid placement is difficult, and especially the acidizing stimulation of long-interval highly deviated wells or horizontal wells is more difficult. In this paper, the diverting mechanism and rheological behavior of viscoelastic surfactant (VES) based diverting acid was firstly investigated, and the diverting acid with good diversion performance and low secondary damage was selected as the main acid. Then, based on the experimental results of its rheological behaviors, an empirical model of effective viscosity was fitted and a two-scale wormhole propagation model was coupled. And accordingly, a mathematical model for the acidizing of self-diverting acid was established to simulate the pH value, Ca2+ concentration, effective viscosity and wormhole shape under the effect of diverting acid in long-interval highly deviated wells that are non-uniformly damaged. Finally, gelled acid and 5% VES diverting acid were compared in terms of their etched wormhole shapes, flow rate distribution and acid imbibition profiles. It is shown that the diverting acid can obviously improve the acid imbibition profile of strong-heterogeneity reservoirs to intensify low-permeability reservoir stimulation. In view of the strong heterogeneity of Longwangmiao dolomite reservoirs and the complexities of drilling and completion fluid damage in the Sichuan Basin, a placement technology was developed for variable VES concentration diverting acid in horizontal wells and long-interval highly deviated wells completed with slotted liners. This acid placement technology has been practically applied in 8 wells and their cumulative gas production rate tested at the wellhead is 1233.46 × 104 m3/d. The average production stimulation ratio per well is up to 1.95. It provides a support for the efficient development of the Longwangmiao giant gas reservoir. Keywords: Sichuan Basin, Early Cambrian, Longwangmiao Fm gas reservoir, Dolomite, Diverting acid, Rheological behavior, Matrix acidizing, Numerical simulation, Field application, Highly-efficient development

When gas invasion, especially overflow, occurs at the bottom hole in the process of managed pressure drilling (MPD), it is common to apply backpressure on the wellbore by adjusting the backpressure pump and throttle valve, so as to rebuild bottom hole pressure balance. If it is still thought that the wellhead backpressure is loaded to the bottom hole instantaneously, there will be larger errors between the calculated wellbore parameters and the actual wellbore flow parameters, which will result in well control failure and even well blowout. In this paper, a pressure wave propagation equation suitable for the gas–liquid two-phase flow in the annulus was established based on the global averaged gas–liquid two-phase flow model to investigate the propagation velocity and time of backpressure wave in the wellbore. Then, gas–liquid interaction was introduced to carry out coupling solution on the equation set. It is shown that pressure wave velocity increases with the increase of drilling mud density, but decreases with the increase of void fraction and virtual mass force coefficient. It changes drastically at first, and then slows down. What's more, when the void fraction is greater than 0.1 or the virtual mass force coefficient exceeds 0.2, the momentum between gas phase and liquid phase is fully exchanged, and the pressure wave velocity decreases slowly, approaching a stable value. In Well Penglai 9 in the Sichuan Basin, for example, the average time of single pressure wave propagation is about 50 s, and the total propagation time of 4 rounds is about 200 s, which accounts for more than 67% of the total time of system control response. It is indicated that the propagation velocity and time of the pressure wave in the annulus calculated by this method can greatly improve the accuracy of managed pressure response time of MPD drilling system and the control precision of adaptive throttle valve. Keywords: Managed pressure drilling (MPD), Gas invasion, Gas–liquid two-phase flow model, Virtual mass force coefficient, Gas–liquid two-phase flow, Pressure wave propagation equation, Pressure wave velocity, Managed response time

In this study, an extended two-fluid model (TFM) describing the gas-liquid two-phase flow when gas influx occurs and an acoustic model describing sound propagation within section of marine riser are proposed. The TFM and acoustic model are validated by comparison of the simulation results and filed data for pit gain, and the experimental tests on a custom-designed acoustic gas influx equipment respectively. These two models are coupled by the pressure of sound and solved using finite volume method. Moreover, two signal processing methods in acoustic gas influx detection based on Fourier transform (FT) and Hilbert-Huang transform (HHT) are introduced. Fourier spectrums and Hilbert-Huang spectrums of the simulated signals are presented in time-frequency or time-amplitude distributions respectively. The results show that compared with wellhead detection methods (WDM) which detect the variation of parameters such as pit gain, the two acoustic detection methods which are based on FT and HHT are more sensitive, and the sensitivity of the HHT method is the highest. The acoustic detection method based on HHT is effective and reliable to be further employed for well control and gas influx detection.

The formation of a brine geyser erupting from the wellhead of a large underground salt cavern is described. In most cases, the brine outflow from an opened cavern is slow; it results from the cavern creep closure and the thermal expansion of the cavern brine. These two processes are smooth; however, the brine outflow often is bumpy, as it is modulated by atmospheric pressure variations that generate an elastic increase (or decrease) of both cavern and brine volumes. In addition, when the flow is fast enough, the brine thermodynamic behavior in the wellbore is adiabatic. The cold brine expelled from the cavern wellhead is substituted with warm brine entering the borehole bottom, resulting in a lighter brine column. The brine outflow increases. In some cases, the flow becomes so fast that inertia terms must be taken into account. A geyser forms, coming to an end when the pressure in the cavern has dropped sufficiently. A better picture is obtained when head losses are considered. A closed-form solution can be reached. This proves that two cases must be distinguished, depending on whether the cold brine initially contained in the wellbore is expelled fully or not. It can also be shown that geyser formation is a rare event, as it requires both that the wellbore be narrow and that the cavern be very compressible. This study stemmed from an actual example in which a geyser was observed. However, scarce information is available, making any definite interpretation difficult.

The transition laws of multiphase flow in a wellbore during acid-gas mixture influx are important for the hydraulic parameters design and wellbore pressure control in acid gasfield drillings. Herein, the phase change of acid-gas mixture in a wellbore was investigated by the experimental analysis. The results indicate that the acid-gas mixture in the supercritical phase exists under conditions of certain wellbore temperature and pressure, which makes its physical properties change abruptly near the critical point. Moreover, considering the phase change and dissolution of acid-gas mixture in drilling fluids, the multiphase flow may go through in turn the single phase flow, supercritical-liquid two phase flow, liquid-liquid two phase flow and gas-liquid two phase flow (including bubbly flow, slug flow, churn flow and annular flow) with the mixed fluids rising from bottom hole to wellhead. Meanwhile, the flow transition criteria, drift flux models and friction factor calculating methods for this type of multiphase flow were proposed. Finally, the multiphase flow characteristics in a wellbore during acid-gas mixture influx were analyzed using the new method with an example. The results suggest that during the acid-gas mixture rising up along the wellbore, the flow pattern transforming from the supercritical-liquid two phase flow or the liquid-liquid two phase flow into gas-liquid two phase flow can cause a large volume expansion, increasing the blowout risk.

Summary Pushing the frontier of oil exploration and production into more-challenging environments and more-frequent interventions and workover operations in subsea wells has led to an increased focus on the structural integrity of a subsea wellhead (WH) and its capability to withstand the fatigue damage it will be subjected to throughout the well's life cycle. The renewed interest led, among other works, to the publication of a WH-fatigue-analysis method statement (MS)1 in 2011, followed by a recommended practice (RP) (DNVGL-RP-01422015), both by Det Norske Veritas Germanischer Lloyd (DNVGL). The MS aimed to reflect the best practices in the industry and to provide a consistent analysis procedure that would ensure the comparability of the results. However, although it thoroughly described the modeling of the WH, the MS deferred the incorporation of wellbore thermal effects, whereas the RP (DNVGL-RP-01422015) only briefly mentions that the effect of temperature should be considered. This perhaps responds to a lack of studies on how this may be taken into account or scarce knowledge about how the variations of wellbore-temperature distribution might affect fatigue damage on the WH. This study describes a numerical approach to increase the scope of the current WH-fatigue-assessment methodology by incorporating the well-temperature distribution into the fatigue analysis. A representative case study of a typical drilling operation in the North Sea has served to investigate how temperature may affect the WH cyclic stresses and the estimates of fatigue-damage rates over time for different cement-sheath levels between the conductor and surface casing.

This paper presents a spatial model of riser dynamics formulated using the segment method and its applications. The model has been validated by comparison of the authors’ own results with those obtained from experimental measurements and Abaqus on the basis of forced vibration with large amplitude for the riser submerged in water. The influence of the sea environment is considered. Correctness and numerical effectiveness of the model enable us to formulate and solve the force stabilisation problem. A dynamic optimisation problem is formulated and solved. As a result vertical courses of movement of the upper end of the riser are obtained which compensate the horizontal movement of the base and stabilise the force in the connection of the riser with a wellhead.

Ship transport and pipeline transport of CO2 are considered to be viable options for large scale CCS. While pipeline transport is usually recommended for shorter distances, ship transport might also be considered for these distances in the early stage of CCS due to its high flexibility and low capital expenses. Ship transport is usually carried out in liquefied state at a temperature around −50 °C and low pressures. Thus, an efficient liquefaction process is required. Unlike other works on CO2 liquefaction, it is assumed that the CO2 has been transported by pipeline before it is transported by ship. Consequently, the CO2 is expanded instead of being compressed and purification is not necessary as it has already been carried out before pipeline transport. Basic 1-stage, 2-stage and 3-stage closed cycle liquefaction processes are modelled, showing that a significant reduction of the minimum specific energy demand can be obtained by employing a multi-stage cascade design. The energy demand for the 2-stage base process is approximately 39% lower than for the 1-stage process. The energy demand can be further reduced by approximately 13% with a 3-stage process. Four measures of optimisation have been analysed: For the CO2 stream, energy recovery with a liquid expander and a two phase expander are investigated. For the refrigeration cycle, the use of an aftercooler and the replacement of the cascade heat exchanger by a phase separator is studied. It can be seen that the energy demand can be reduced by approximately 30%–40% with respect to the base process if those four measures are implemented. The impact of the optimisations is influenced by the impurity concentrations of the CO2 stream. Besides liquefaction, the specific electrical and thermal energy demands for the injection of CO2 have been calculated. The electrical energy demand is proportional to the wellhead pressure and was found to be between 1.9 kWh/t CO2 and 7.8 kWh/t CO2. The thermal energy demand is between 21.0 kWh/t CO2 and 30.5 kWh/t CO2, increasing for higher wellhead pressures and impurity concentrations.

The ability to transfer crude oil through pipelines from wellhead to refinery without any complication is dealt with midstream flow assurance. Crude oil deposits are found in reservoir under high temperature and pressure which when extracted and transported through pipelines results in drastic changes in their process condition thereby leading to several problems. Conventional methods like electric, emulsification and thermal insulation are highly expensive and often require regular pigging in crude pipelines. Here, Pour Point Depressant (PPD) plays a significant role in reducing the problems faced in pipeline transportation in midstream sector. One of the advanced and recent methods of using PPD is gaining importance over conventional methods due to the ease in handling the different types of crudes. To make this possible, different types of PPDs are employed to encounter various problems. This review discusses the necessity and importance of PPDs, their types, mechanism, nature, advantages etc. in detail. It also touches upon the conventional and a few other techniques applied.

A unified mathematical model, considering the two mechanisms of static-dynamic friction conversion and friction decomposition, is developed to analysis the effect of different vibration manners and parameters on axial load transfer and tool face of positive displacement motor and evaluate the vibration level and dynamic security of the drill-string. A second-order finite difference method is used to solve this model. The change of weight on bit, rate of penetration and tool face of positive displacement motor under three different slide drilling manners are obtained. Simulation results show that the vibrations applied on drill-string mitigate the stick-slip and adhesion phenomenon and make the load transfer and movement of the drill-string smoother. The increment of weight on bit is the combined effect of the change of axial friction acting on drill-string and the exciting force. Among the three vibration manners, the axial vibration applied at bottom hole has the best friction reduction and tool face stabilization effects and the lowest vibration intensity. The torsional vibration applied at wellhead mainly affects the upper drill-string and has an optimal torsion angle subject to the torsional depth. The axial vibration applied at wellhead has a strong effect on the drill-string of vertical section. Results provide guidance and advice to the research and applications of friction reduction by vibrating drill-string.

Gas production from multiple coal seams has become common practice in many coal basins around the world. Although gas production rates are typically enhanced, the economic viability of such practice is not well studied. In order to investigate the technical and economic feasibility of multiple coal seams production, reservoir simulation integrated with economics modelling was performed to study the effect of important reservoir properties of the secondary coal seam on production and economic performance using both vertical and horizontal wells. The results demonstrated that multiple seam gas production of using both vertical and horizontal wells have competitive advantage over single layer production under most scenarios. Gas content and permeability of the secondary coal seam are the most important reservoir properties that have impact on the economic feasibility of multiple seam gas production. The comparison of vertical well and horizontal well performance showed that horizontal well is more economically attractive for both single well and gas field. Moreover, wellhead price is the most sensitive to the economic performance, followed by operating costs and government subsidy. Although the results of reservoir simulation combined with economic analysis are subject to assumptions, multiple seam gas production is more likely to maintain profitability compared with single layer production. Keywords: Multiple coal seam, Production simulation, Economic viability, Sensitivity, Coalbed methane

At present, the study of supercritical water (SCW) flow in wellbores is at the starting stage. In this paper, a simple but useful model is developed to study the effect of seawater on the thermophysical properties of SCW in offshore vertical wellbores. Firstly, based on the momentum and energy balance equations, a flow model describing SCW flow in a tube is established. Then, coupled with transient heat transfer model in seawater and formation, and thermophysical parameters of SCW, a comprehensive mathematical model is established. In order to solve the model, the governing equations are expressed in the form of difference equations. The straight forward numerical method is adopted to solve the model from wellhead to well-bottom. In the process of solving, iterative technique is used to control the calculation accuracy. Finally, type curves of SCW flow in offshore wellbores and sensitivity analysis are discussed. Results show that (a) the flow of seawater results in a rapid decline in the temperature/enthalpy of SCW in wellbores. (b) Heat loss is the dominant factor of physical parameter distribution in wellbores when the injection rate is relatively small. (c) Heat loss has an obvious influence on temperature drop when SCW is sparse in volume. (d) The SCW pressure decreases with increasing of injection temperature.

Numerous models have been developed for calculating the fate of crude oil and natural gas plumes after deep-sea oil spills. One of the most important input parameters for these models is the rise velocity of fluid particles under the extreme environmental conditions in the deep sea (high pressure, low temperature). Consideration of these conditions in combination with the respective fluid properties, especially gas solubility in released crude oil under high pressure, is crucial for both droplet formation at the wellhead and drop rise through the water column. A model for calculation of oil-droplet rise velocities under consideration of the pressure-dependent gas-in-oil solubility is presented and validated. For this purpose, the concept of “internal degassing” that leads to a higher buoyancy of crude-oil droplets and thus an accelerated drop rise is introduced. Calculation of three different drop-rise scenarios showed high impact of this effect. For the first time high-pressure experiments using...

The majority of gas and gas condensate fields of Ukraine are developed by pressure depletion, which makes it possible to stabilize production only in conditions of low working pressures at the wellhead. In turn, the working pressure values significantly depend on the pressure at the inlet to the gas gathering stations and pressure loss in the gas gathering and transportation process. Consequently, their reduction will lead to an increase in natural gas production from depleted fields. The main idea of the work is to offer continuous monitoring of the gas gathering system in order to detect changes in the thermobaric operation mode. Such changes can signal the high probability of liquid accumulation, which will produce additional friction. The results of monitoring changes in pressure, temperature, dew points and natural gas composition allow carrying out their complex analysis and evaluating the possibility of liquid mass formation in certain areas of the gas pipeline system with an acceptable accuracy, which at once excludes a more detailed recording of their presence by means of instrument equipment and human resources, as well as reduces the time of non-response to a problem. The works may be fully executed by the operations technician or the dispatch service. After detecting potentially hazardous places, they are analyzed for confirmation of the presence of liquid and the decision to clean them with one of the proposed methods is made. This approach will be very interesting to large international companies, since natural gas reserves are constantly exhausted, and withdrawal of the remaining gas from depleted fields is an attractive target for producing companies. In addition, the use of simple pigging methods based on the analysis of the hydraulic efficiency of pipelines can significantly reduce both time and material resources.

Purpose Numerical simulations of a multistage multiphase pump at different operating conditions were performed to study the variational characteristics of flow parameters for each impeller. The simulation results were verified against the experimented results. Because of the compressibility of the gas, inlet volume flow rate qi and inlet flow angle ßi for each impeller decrease gradually from the first to the last stage. The volume flow rate at the entrance of the pump q, rotational speed n and inlet gas volume fraction (IGVF) affect the characteristics of qi and ßi. Design/methodology/approach The hydraulic design features of the impellers in the multistage multiphase pump are obtained based on the flow parameter characteristics of the pump. Using the hydraulic setup features, stage-by-stage design of the multistage multiphase pump for a nominal IGVF has been conducted. Findings The numerical simulation results show that hydraulic loss in impellers of the optimized pump is substantially reduced. Furthermore, the hydraulic efficiency of the optimized pump increases by 3.29 per cent, which verifies the validation of the method of stage-by-stage design. Practical implications Under various operating conditions, qi and ßi decrease gradually from the first to the fifth stage because of the compressibility of the gas. For this characteristic, the fluid behavior varies at each stage of the pump. As such, it is necessary to design impellers stage by stage in a multistage rotodynamic multiphase pump. Social implications These results will have substantial effect on various practical operations in the industry. For example, in the development of subsea oilfields, the conventional conveying equipment, which contains liquid-phase pumps, compressors and separators, is replaced by multiphase pumps. Multiphase pumps directly transport the mixture of oil, gas and water from subsea oilwells through a single pipeline, which can simplify equipment usage, decrease backpressure of the wellhead and save capital costs. Originality/value Characteristics of a multistage multiphase pump under different operating conditions were investigated along with features of the inlet flow parameters for every impeller at each compression stage. Our simulation results have established that the change in the inlet flow parameters of every impeller is mainly because of the compressibility of the gas. The operational parameters q, n and IGVF all affect the characteristics of qi and ßi. However, the IGVF has the most prominent effect. Lower values of IGVF have an insignificant effect on the gas compressibility. Higher values of IGVF have a significant effect on the gas compressibility. All these characteristics affect the hydraulic design of the impellers for a multistage multiphase pump. In addition, the machining precision should also be considered. Considering all these factors, when IGVF is lower than 10 per cent, all the impellers in the pump can be designed uniformly. When IGVF varies from 10 to 30 per cent, the first two stages should be designed separately, and the latter stages are uniform starting with the second stage. When IGVF varies from 30 to 50 per cent, the first three stages should be designed separately, and the latter stages are going to be similar to the third stage. An additional increase in IGVF results in degeneration of the differential pressure of the pump, which will reduce the compressibility of the gas. As such, it can be deduced that only the first three stages should be designed separately, and the latter stages will be similar to the third stage. In addition, for the pump working under a lower volume flow rate than 25 m3/h, the first three stages should be designed individually while keeping the geometrical structure of the subsequent stages the same as the third stage.

More than 90% of natural gas hydrates (hereinafter, hydrate for short) in the South China Sea are non-diagenetic ore bodies, so they cannot be exploited easily by means of the conventional methods. In this paper, the solid fluidization method, as one of the revolutionary technologies in efficient exploitation of non-diagenetic natural gas hydrates, was, for the first time, put forward by Academician Zhou Shouwei. And it is successfully applied in the Shenhu Area of the South China Sea based on the technologies, equipment and processes which rely on domestic independent intellectual property rights. During the production test of fluidization, the ore bodies of hydrates are broken by the jet at the bottom hole into fine particles and carried upward by the drilling fluid. When the phase equilibrium state is reached with the increase of temperature and the decrease of pressure affected by the operation parameters, which is different from conventional phase equilibrium state, the hydrates bearing solid particles are decomposed, and consequently liquid–solid flow in the annulus becomes complex gas–liquid–solid multiphase flow. Therefore, it is necessary to optimize the construction parameters design so as to meet the high-level requirements of well control safety. In this paper, the engineering parameters are optimally designed based on the engineering geological characteristics of the target block, combined with the analysis on complex multiphase flow in the wellbore. Then, a theoretical model and a numerical calculation method for the multiphase flow, temperature and pressure of complex media in wellbores and the phase equilibrium and decomposition of natural gas hydrates were established. And the multiphase flow in the wellbore during the production test of fluidization was analyzed under different operating parameters by means of numerical simulation, software emulation and experimental verification. And thus, the design optimization scheme of on-site engineering parameters of production test of marine natural gas hydrate fluidization was prepared. It is pointed out that the diameter of jet fluidization well section shall not be excessively large; and that it is necessary to increase the flow rate and density of drilling fluid and apply wellhead back pressure to ensure the cutting carrying safety and to mitigate well control risks. The results of this basic theoretical study can provide significant support to field operation and improvement of output in production tests. Keywords: Marine, Natural gas hydrate, Non-diagenetic, Solid fluidization, Production test, Jet breakup, Multiphase flow, Engineering parameter, Numerical simulation, Optimal design, China, Shenhu sea area, South China sea

The modeling of thermal fluid (mostly reported for saturated steam) flow in wells involving steady-state heat transfer inside wellbores and transient heat transfer in sea water or formation is reviewed and inherited. It is a good addition of modeling of supercritical/superheated fluid to the existing body of literature. The flow of supercritical CO2 coupled with superheated water (SHW) in offshore wells is described by means of the differential mass, energy and momentum balance equations along the vertical wellbores. The effect of supercritical CO2 on pressure and temperature of the multi-component thermal fluid is expressed in terms of the real gas model (the S-R-K model). The differential equations are solved with finite difference method on space involving the constant injection parameters at wellhead. It is found out that: (a). while seawater has a significant influence on temperature drop in wellbores, its effect on pressure profiles is weak. (b). both temperature and superheat degree decrease with increasing of the content of supercritical CO2. Besides, study of the effect of injection rate and pressure is conducted.

Most of the major oilfields in the North Sea, Persian Gulf and South China Sea are becoming very mature, with their assets exceeding their calculated design life. Severe corrosions on the metallic structures of oil wells consisting of the conductor and casings, combined with spalling of annular cement forming the barriers can result in catastrophic events leading to structural collapse and wellhead vertically dropping onto the platform deck. With the collected inspection records, a systematic approach is deemed essential to assess the in-place condition of these wells and to categorise them for life extension works. This paper presents a simplified screening method for the structural integrity assessment of platform conductors towards the end of their design life and the prioritisation which follows thereafter for life extension operations by bridging the gap between design data and inspection records. The deterministic and probabilistic integrated approach is taken to address this problem, by considering the information collected from the as-built design records to the in-place inspections, coupled with the operating and metocean loads. The pragmatic and novel conductor operating guideline curves are proposed and constructed to present the evaluated integrity states, which will enable operators to rapidly categorise conductors for rehabilitation. This screening method is applied to a group of 40-year old water injection wells, and is demonstrated to have the practical prospect, and can be automated to provide a robust and effective assessment technique.

Capture zone delineation has been in practice for decades as a part of groundwater management and wellhead protection schemes. The energy possessed by a groundwater particle gets continuously dissipated as it traverses along its path and, is the work done by it. The study of energies within any domain probes into the innate nature of the system and its interaction with the surroundings. Hence energy computations in and around the realms of extraction wells can be used to analyze capture zones from the energy concept. There has been very little research reported on the energy of groundwater flow and specifically that associated with the well capture zones. This work intends to model two-dimensional homogeneous isotropic confined aquifers using finite volume method, then delineate the capture zones and examine the energies within. Steady state aquifer conditions will cause all the work done at the boundaries converted into frictional dissipation. This frictional dissipation was found significant over regions of 95% capture surrounding the well within the capture zone.

Mineral scaling is a common problem in geothermal power facilities. This scale deposition is usually caused by changes in the geothermal fluid temperature or composition and chemistry. Precipitation of minerals can limit fluid flow within the steam field equipment, reducing plant efficiency and increasing maintenance costs. A layer of scaling is commonly found in most parts of the geothermal steam gathering system. However, significant amounts of deposited mineral scales are usually observed in the pipelines and vessels that handle silica super-saturated brines. This work focuses on a less common scaling in geothermal two-phase pipelines, when fluids are usually high enthalpy and under-saturated with respect to amorphous silica. The scaling is mainly caused by mixing and changes in steam fraction at the two-phase pipelines, when several wells share the same pipeline header to transport the fluid to the downstream facility. Two case studies are discussed in this work reporting mineral scaling due to the mixing of incompatible geothermal fluids within two-phase headers. The first case investigates silica deposition caused by the mixing of a steam-dominated well fluid with fluid from two water-dominated wells. The scale deposition is caused by the small amount of brine entrained in the steam-dominated well fluid, which reacts upon mixing with the fluid from the other water-dominated wells, causing massive localised scaling at the mixing points. The second case investigates iron sulfide and silica deposition caused by the mixing of a low-pH, high-silica fluid with neutral-pH fluid. Header blockage can result in an increase in wellhead pressures causing production from some wells to collapse, at the same time decreasing the flow of geothermal fluids to the separators. The scaling requires regular cleaning to return the pipelines to full flow capacity. Recommended engineering solutions are given for both cases, for possible site implementation.

When completing deepwater wells, a significant portion of the completion fluid is often trapped in the casing annuli because of widespread use of multi-layer casing technology. When transferred into testing or production, the temperature field in the immediate vicinity of the wellbore is redistributed by any present thermally conductive fluids. Raising trapped completion fluid to a high temperature can trigger high thermal stress, and this stress has been proven to present a grave threat to the safety of deepwater wells. In this paper, a thermal conductivity model of fluid-filled annuli based on a typical well structure used in the South China Sea is established to determine the effect of different production parameters during the well production or testing process on pressure behavior. A numerical simulation of the effects of fluid trapped in the casing annuli on temperature distribution was conducted. Based on this simulation, a novel method for mitigating the pressure of the trapped fluid by a way of a unidirectional control strategy was studied, and a unidirectional pressure control casing nipple tool was developed. Laboratory simulations were then conducted using a prototype tool to determine the technical feasibility of the unidirectional control strategy. The change in trapped fluid pressure with time was obtained for different release pressures and tool valve orifice diameters, showing the effects of different valve orifice diameters and volumetric injection rates on the pressure release performance. Experimental results demonstrate that the pressure envelope decreases quadratically with the increase in the pressure grade, while the valve working duration decreases linearly with the increase in valve orifice diameter. The increase in the volumetric injection rate was found to have little effect on the cumulative volume displacement. The proposed unidirectional pressure control strategy for controlling the accumulation of pressure in the annuli of deepwater wellbore casings can effectively eliminate the fatal dangers presented by thermal stress. It can also reduce the risk of casing deformation due to thermal stress within trapped annuli and reduce occurrences of wellhead sealing damage.

The main goal of this paper is the identification of natural frequencies and damping ratios within the operating range of an electrical submersible pump set (ESP), which could lead to operation in resonance condition. The ESP set was installed in a mock well and the excitation was through an impact hammer on the production column, at the wellhead. Only the structure’s acceleration responses were measured. Two versions of the Ibrahim time domain (ITD) method were used: the single station time domain and the transformed stations. Both methods were able to identify the modal parameters, but the latter is more efficient.

To solve the difficulties in exploration and development in Yuanba ultra-deep gas field in Sichuan Basin, SW China, the article studies the mechanism of quality reef reservoirs development and gas accumulation and innovates techniques in ultra-deep seismic exploration, drilling, completion and testing. Through the reconstruction of dynamic depositional evolution process and regional depositional framework of homoclinal ramp-rimmed platform in Upper Permian, three theories are put forward: first, “early beach-late reef, multiple stacking, arrangement in rows and belts” is the sedimentary mode for the reservoirs in the Changxing Formation of Yuanba area; second, “dissolution in early exposure stage and dolomitization during shallow burial giving rise to the pores in matrix, overpressure caused by cracking of liquid hydrocarbon during deep burial inducing fractures” is the reservoirs development mechanisms; third, “coupling of pores and fractures” controls the development of high quality reservoirs in deep formations. From correlation of oil and source rock, it is concluded that the Wujiaping Formation and Dalong Formation of deep-water continental shelf are the major source rocks in the Permian of northern Sichuan Basin. The hydrocarbon accumulation mode in ultra-deep formations of low-deformation zones is characterized by “three-micro (micro-fault, micro-fracture interbed crack) migration, near-source enrichment, and persistent preservation”. Through seismic inversion using the pore structure parameters of pore-fracture diadactic structure model, the high production gas enrichment area in Yuanba gas field is 98.5 km2. Moreover, special well structure and unconventional well structure were used to deal with multiple pressure systems and sealing of complex formations. A kind of integral, high pressure resistant FF-level gas wellhead and ground safety linkage device was developed to accomplish safe and environmentally friendly gas production. Key words: Sichuan Basin, Yuanba gas field, ultra-deep formation, Changxing Formation, reef, seismic exploration, testing technology

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.

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 202439, “Pushing Malaysia’s Drilling Industry Into a New Frontier: How a Distinctive Wellhead Design Enabled Implementation of a Fully Offline Well Cementing Resulting in a Significant Shift in Operational Efficiency,” by Fauzi Abbas and Azrynizam M. Nor, Vestigo, and Daryl Chang, Cameron, a Schlumberger Company, prepared for the 2020 SPE Asia Pacific Oil and Gas Conference and Exhibition, originally scheduled to be held in Perth, Australia, 20–22 October. The paper has not been peer reviewed. Traditionally, rigs are positioned over a well from the moment the surface casing is drilled until the installation of the wellhead tree. This results in the loss of precious time as the rig idles during online cementing. However, in mature Field A offshore Terengganu, Malaysia, a new approach eliminated such inefficiency dramatically. Operational Planning With oil production in Field A initiated in October 2015, historical data on well lithology, formation pressure, and potential issues during drilling were available and were studied to ensure that wells would not experience lost circulation. This preplanning is crucial to ensure that the offline cementing activity meets the operator’s barrier requirements. Petronas Procedures and Guidelines for Upstream Activities (PPGUA 4.0) was used for the development of five subject wells in Field A. In this standard, two well barriers are required during all well activities, including for suspended wells, to prevent uncontrolled outflow from the well to the external environment. For Field A, two barrier types, mechanical and fluid, allowed by PPGUA 4.0 were selected to complement the field’s geological conditions. As defined in PPGUA 4.0, the fluid barrier is the hydrostatic column pressure, which exceeds the flow zone pore pressure, while the mechanical barrier is an element that achieves sealing in the wellbore, such as plugs. The fluid barrier was used because the wells in Field A were not known to have circulation losses. For the development of Field A, the selected rig featured a light-duty crane to assist with equipment spotting on the platform. Once barriers and rig selection are finalized, planning out the drill sequence for rig skidding is imperative. Space required by drillers, cementers, and equipment are among the considerations that affect rig-skid sequence, as well as the necessity of increased manpower. Offline Cementing Equipment and Application In Field A, the casing program was 9⅝×7×3½ in. with a slimhole well design. The wellhead used was a monobore wellhead system with quick connectors. The standard 11-in. nominal wellhead design was used for the wells with no modifications required. All three sections of the casing program were offline cemented. They were the 9⅝-in. surface casing, 7-in. production casing, and 3½-in. tubing. The 9⅝-in. surface casing is threaded to the wellhead housing and was run and landed with the last casing joint. Subsequent wellhead 7-in. casing hangers and a 3½-in. tubing hanger then were run and landed into the compact housing.

Developing a model that can accurately predict the hydrocarbon production by only employing the conventional mathematical approaches can be very challenging. This is because these methods require some underlying assumptions or simplifications, which might cause the respective model to be unable to capture the actual physical behavior of fluid flow in the subsurface. However, data-driven methods have provided a solution to this challenge. With the aid of machine learning (ML) techniques, data-driven models can be established to help forecasting the hydrocarbon production within acceptable range of accuracy. In this paper, different ML techniques have been implemented to build the models that predict the oil production of a well in Volve field. These techniques comprise support vector regression (SVR), feedforward neural network (FNN), and recurrent neural network (RNN). Particle swarm optimization (PSO) has also been integrated in training the SVR and FNN. These developed models can practically estimate the oil production of a well in Volve field as a function of time and other parameters: on stream hours, average downhole pressure, average downhole temperature, average choke size percentage, average wellhead pressure, average wellhead temperature, daily gas production, and daily water production. All these models illustrate splendid training, validation, and testing results with correlation coefficients, R2 being greater than 0.98. Moreover, these models show good predictive performance with R2 exceeding 0.94. Comparative analysis is also done to evaluate the predictability of these models.

Tight gas reservoirs are characterized by multiple thin and vertically distributed development layers with similar or different lithology and varying geological conditions. To increase the production per well and reduce development costs, field experts have widely adopted the commingled production of tight gas in multi-layer reservoirs. However, differences in reservoir properties and pressure might lead to interlayer interference which could influence the overall wellhead output. In this study, we propose a mathematical model for predicting the overall wellhead output of single and multi-layer tight gas reservoirs after interlayer interference. A reservoir(a) and process factor(b) were deduced to quantitatively analyze the difference in interlayer interference. The range and accuracy of the model were analyzed through a goodness-of-fit test. The results showed that the interlayer interference in multi-layer commingled production systems with three or more layers was decreasing, and the interlayer interference in multi-layer commingled production systems with three or more layers was not significantly affected by the increment of layers, the accuracy of the model was greater than 80% and closer to the lower limit of the process and reservoir factors. The model will provide a quantitative method for predicting interlayer interference in multi-layer commingled production, a reliable basis for understanding the mechanism of interlayer interference, and a theoretical framework for evaluating the feasibility of commingled production in multi-layer tight gas reservoirs.

As discussed in part I of this work, the wellhead is an important component in the context of well integrity and operational safety, as it serves as a link between well and riser in offshore oil wells. The wellhead must sustain loads from the casings (soil reaction), which are hung into it through the casing hangers, as well as sustain loads from the riser (waves, current), which is connected at the top of the BOP (right above the wellhead) through the lower flex joint. In Part I of this work, we proposed a deterministic methodology to evaluate excessive wellhead motions, considering a mechanical system that couples the vessel, the riser, the wellhead itself, the conductor and surface casings, and their interaction with the soil. Now, in Part II, we move onto a stochastic analysis, which allows us to calculate the wellhead reliability. The simulation of this system provides the motions experienced by the wellhead; then, criteria such as maximum allowable lateral deflection and maximum allowable rotation are applied to verify if they will cause wellhead failure. Several interesting results have been observed: modern 5-phase wells with cemented conductor confer higher integrity to the wellhead compared to old 4-phase wells with jetted conductors; current speed/profile is the variable that affects the most the wellhead reliability; and heavier inner fluids reduce the reliability, posing a problem for later drilling phases. Finally, an integrity index for the wellhead throughout the well life cycle is suggested, aggregating the literature related to wellhead fatigue failure. The wellhead integrity index can then be combined with other indexes from other barrier elements to evaluate the overall integrity of barrier envelopes.

Hydrogenated nitrile butyl rubber (HNBR) elastomers are highly resistant to chemicals and degradation, and they are good candidates to be adopted in aggressive environmental conditions of high temperature and pressure. As these service parameters are common in oil and gas applications, HNBR is popular in applications such as elastomer packers in wellhead installations. This study investigated the thermal ageing behaviour of HNBR elastomers to better predict the long-term sealing performance of the packers. Elastomer compounds were thermally aged and FTIR-ATR and differential scanning calorimetry techniques were used to indicate dominant chemical reactions during ageing. Furthermore, the mechanical performance of the aged compounds were studied to investigate the effect of dominant ageing reactions on performance. It was indicated that crosslinking reaction was dominant in the ageing process of HNBR compounds up to 150 °C. This resulted in increased stiffness and alleviated elongational strains at the break. However, compounds behaved brittle at ageing temperatures above 150 °C, and from the thermal analysis, it was concluded that at those temperatures chain scission reactions overtook the ageing mechanism. Finally, an approach for life-long prediction of mechanical characteristics of the specimens showed while long-term ageing promotes elastic failure, ageing temperatures above 150 °C facilitate rupture because of the brittle response of the compounds.

The wellhead is an important component in the context of well integrity and operational safety, as it serves as a link between well and riser in offshore oil wells. Wellheads, combined with the BOP and/or the Christmas tree, act as the final barrier element preventing leakage of oil from the well into the environment. The wellhead must sustain loads from the casings (soil reaction), which are hung into it through the casing hangers, as well as sustain loads from the riser (waves, current), which is connected at the top of the BOP (right above the wellhead) through the lower flex joint. In Part I of this work, we propose a deterministic methodology to evaluate wellhead motions, considering a mechanical system that couples the vessel, the riser, the wellhead itself, the conductor and surface casings, and their interaction with the soil. The limiting factor in this study is the excessive motions experienced by the wellhead, which can lead to well integrity problems such as dislodgment of the conductor casing or a poor cementing job. The simulation of this system provides the motions experienced by the wellhead, through simulation of some well design choices (use of jetting base, conductor casing size, and cemented conductor). Results have shown that modern 5-phase wells with cemented conductor confer higher integrity to the wellhead compared to old 4-phase wells with jetted conductors, while the jetting base has not affected the wellhead motions significantly. These results are extended in Part II, which incorporates a stochastic analysis.

The dispersion coefficient is a key physical parameter for enhanced gas recovery (EGR) and reflects the degree of mixing between the displacing-fluid CO2 and natural gas. However, no comprehensive overview of existing research on EGR dispersion characteristics has been conducted to date. In this review article, previous experimental and simulation studies are summarized to provide an overview of the current research progress and, hence, to elucidate the limitations of EGR and identify directions for future research. The literature analysis reveals that temperature and flow rate promote CO2–CH4 dispersion, whereas pressure and residual-water salinity inhibit dispersion under supercritical conditions. The CO2–CH4 dispersion coefficient is smaller in porous media with high permeability. However, on the core scale, the effects of residual water on the CO2 dispersion and breakthrough time are controversial and further verification is required. To date, only limited research has been conducted on the effects of impurities under supercritical conditions, such as considering CO2 containing N2, and CH4 containing CO2, N2 and ethane. Existing pilot EGR trials are insufficient to provide standardized field operation instructions, for example, with regard to the wellhead layout. Field-scale simulations have verified the feasibility of EGR technology and economy. However, factors such as the permeability heterogeneity, initial water saturation distribution, connate water salinity, gas-reservoir non-isothermal conditions, and vertical stratification should be considered in simulations of actual gas reservoirs. More in-depth experimental and simulation-based investigations of EGR should be performed on various scales to accurately assess the dispersion characteristics and natural-gas recovery efficiency under gas-reservoir conditions.

Condensate reservoirs are the most challenging hydrocarbon reservoirs in the world. The behavior of condensate gas reservoirs regarding pressure and temperature variation is unique. Adjusting fluid flow rate through wellhead chokes of condensate gas wells is critical and challenging for reservoir management. Predicting this vital parameter is a big step for the development of condensate gas fields. In this study, a novel machine learning approach is developed to predict gas flow rate (Qg) from six input variables: temperature (T); upstream pressure (Pu); downstream pressure (Pd); gas gravity (γg); choke diameter (D64) and gas–liquid ratio (GLR). Due to the absence of accurate recombination methods for determining Qg, machine learning methods offer a functional alternative approach. Four hybrid machine learning (HML) algorithms are developed by integrating multiple extreme learning machine (MELM) and least squares support vector machine (LSSVM) with two optimization algorithms, the genetic algorithm (GA) and the particle swarm optimizer (PSO). The evaluation conducted on prediction performance and accuracy of the four HML models developed indicates that the MELM-PSO model has the highest Qg prediction accuracy achieving a root mean squared error (RMSE) of 2.8639 Mscf/d and a coefficient of determination (R2) of 0.9778 for a dataset of 1009 data records compiled from gas-condensate fields around Iran. Comparison of the prediction performance of the HML models developed with those of the previous empirical equations and artificial intelligence models reveals that the novel MELM-PSO model presents superior prediction efficiency and higher computational accuracy. Moreover, the Spearman correlation coefficient analysis performed demonstrates that D64 and GLR are the most influential variables in the gas flow rate for the large dataset evaluated in this study.

Model predictions of oil transport and fate for the 2010 Deepwater Horizon oil spill (Gulf of Mexico) were compared to field observations and absolute and relative concentrations of oil compounds in samples from 900 to 1400 m depth11 km from the well. Chemical partitioning analyses using quantitative indices support a bimodal droplet size distribution model for oil released during subsea dispersant applications in June with 74% of the mass in1 mm droplets that surfaced near the spill site within a few hours, and 1-8% as0.13 mm microdroplets that remained below 900 m. Analyses focused on 900-1400 m depth11 km from the well indicate there was substantial biodegradation of dissolved components, some biodegradation in microdroplets, recirculation of weathered microdroplets into the wellhead area, and marine oil snow settling from above 900 m carrying more-weathered particulate oil into the deep plume.

Managed pressure cementing (MPC) has been successfully used to reduce risk lost circulation and improve cementing quality in wells with a narrow safe pressure window. However, during the waiting setting period of MPC, the magnitude of the managed well backpressure is still based on experience, which results in a high risk of leakage or gas channeling especially in formations with a narrow safe density window. Therefore, a backpressure managing method is proposed here based on a model we built for calculating wellhead backpressure. This model was used to analyze the effect of cement slurry, temperature and wellbore pressure on wellhead backpressure. The results show that hydration, filtration shrinkage and gel supporting are essential to reduce wellbore pressure, although hydration is less effective compared with the latter two on pressure reduction. The magnitude and duration of wellhead backpressure depend on the extent of volume shrinkage and the gel strength development of cement slurry. Latex-cement slurry requires minimal wellhead backpressure with the shortest duration. Temperature and wellbore pressure greatly impact wellhead backpressure with temperature playing a more dominant role.