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The worldwide increase in energy demand necessitates the development and optimization of marginal oil fields for sustenance. In this regard, effective and economic production of fluids are heavily relied upon the artificial lift techniques as the reservoir's natural energy may not be able to deliver the fluids to the surface. Gas lift is a widely practised and successful method that is suitable for rejuvenating the oil production from such fields. In this study, the influence of critical parameters like water cut, wellhead pressure (WHP) and gas-lift gas injection rate on the output from a gas lifted well was analysed. A significant reduction in the oil production was observed with the increase in water cut. For a fixed gas injection rate of 1 Mmscf/day, the production decreased by 26.90% when the water cut increased from 15% to 30% and further by 50.80% when the water cut reached 45%. An increase in the gas injection rate from 1 Mmscf/day to 8 Mmscf/day resulted in an increase in the production rate by 29.21%, 40.48% and 56.56% for 15%, 30%, and 45% water cut conditions, respectively. It was observed that there is a drop in the oil rate with the increase in WHP for a constant gas injection rate. An increase in the WHP from 100 psi to 300 psi resulted in a drop in the oil production rate by 11.01%, 11.78% and 12.74% for 15%, 30% and 45% water cut conditions, respectively. The study sheds light on the significance of optimizing the critical parameters to maximize the production from a well, with severely affected productivity, using a continuous gas lift system.

The natural gas hydrate resources in the South China Sea alone are about 85 trillion cubic meters. In the drilling process of marine gas hydrate, the natural gas hydrate will decompose and produce gas, as the rising of temperature and dropping of the pressure in the annulus. This process will have a significant impact on drilling safety. Therefore, it is necessary to study the wellbore temperature distribution during the drilling of marine hydrate layer. In this paper, the wellbore temperature distribution of safe drilling in hydrated formation is taken as the research goal, and the research status of relevant domestic and international wellbore temperatures was investigated. According to the characteristics of the marine environment and reservoir-forming characteristics of hydrate reservoirs in the South China Sea, the wellbore temperature distribution model of offshore drilling wellbore under the condition of hydrate decomposition was established. The temperature distribution curve of drilling straight wellbore in hydrate layer of South China Sea was obtained. When drilling the hydrate reservoir, the distribution regularity of the wellbore temperature is similar to that of the conventional offshore drilling wellbore. However, the temperature of the wellbore annulus near the hydrate decomposition site is lower than the ambient temperature, mainly due to the hydrate decomposition endothermic. In this paper, the sensitivity analysis of several main parameters of the wellbore temperature distribution of drilling straight wellbore in hydrate layer of South China Sea was carried out. Through the conduction of experiment and numerical simulation, we have get some new findings: (1) The hydrate saturation has little effect on the wellbore temperature; (2) As the drilling fluid displacement increases, the annulus temperature of the wellbore above the mudline increases, and the temperature of the wellbore below the mudline decreases continuously; (3) As the density of the drilling fluid increases, the temperature at the wellhead decreases, and the temperature at the bottom of the well increases slightly; (4) The greater the rate of penetration of the well, the temperature at the upper part of the wellbore decreases, and the temperature at the bottom of the wellbore increases; Among them, the penetration rate has the most obvious effect on the annular temperature. The results are expected to be helpful to guide the drilling process of marine gas hydrate and offer some references.

Steam-assisted-gravity-drainage (SAGD) is currently an effective technology for heavy oil recovery. The pre-heating stage is important to affect the overall process of SAGD development. In this paper, flow and heat transfer model in vertical well section and horizontal well section and thermal connectivity judgment model during cyclic pre-heating stage were established. Model calculation results are in good agreement with actual measurement results. The effects of steam injection rate and steam quality on the distribution of steam parameters along the whole wellbore and the distribution of heat transfer were compared. Besides, the optimization of steam injection parameter combination was provided. Ultimately, the effect of horizontal well spacing on pre-heating thermal connectivity was discussed. The results show that: With the increase of steam injection rate and steam injection quality, the pressure and temperature drop of the fluid increase. Wellhead required steam injection pressure and temperature increases and even superheated steam appear with the increase of steam injection rate and steam injection quality. The position where the pre-heating backflow turns from wet steam to subcooled water gradually shifts to the wellhead. With the increase of steam injection rate and steam injection quality, the heat transfer between annulus and reservoir decreases, but the uniformity of pre-heating in the horizontal section increases. The time required for cyclic pre-heating to form thermal communication between double wells increases significantly as the horizontal well spacing increases. To simultaneously integrate the uniformity and economy of pre-heating on the oilfield site, the steam injection quality at the heel end of the horizontal section of 0.7, the steam injection rate of 80 t/d, and the horizontal well spacing of 5 m were recommended.

Affected by the surrounding injection and production wells, the formation near the infill adjustment well is in an abnormal pressure state, and drilling and completion operations are prone to complex situations and accidents such as leakage and overflow. The conventional shut-in method is to close all water injection wells around the adjustment well to ensure the safety of the operation, but at the same time reduce the oil field production. This paper proposes a design method for shut-in of water injection wells around adjustment wells based on injection-production data mining. This method uses water injection index and liquid productivity index as target parameters to analyze the correlation between injection and production wells. Select water injection wells with a high correlation and combine other parameters such as wellhead pressure and pressure recovery speed to design accurate adjustment schemes. Low-correlation wells do not take shut-in measures. This method was applied to 20 infill adjustment wells in the Penglai Oilfield. The correlation between injection and production wells was calculated using the data more than 500 injection wells and production wells. After a single adjustment well is drilled, the surrounding injection wells can increase the water injection volume by more than 5000 m3. This method achieves accurate adjustment for water injection wells that are high correlated with the adjustment well. Under the premise of ensuring the safety of drilling operations, the impact of drilling and completion on oilfield development is minimized, and oilfield production efficiency is improved. It has good application and promotion value.

In the oil and gas production process in deep-water high-temperature–high-pressure (HT–HP) wells, the occurrence of wellhead uplift is often induced by the heat carried by oil and gas flow from the well bottom to the wellhead. This directly leads to the seal failure of wellhead device, causing the great potential safety hazard. Therefore, the wellhead uplift needs to be studied in cementing designing. The calculation model for the wellbore temperature and pressure field as well as the wellhead uplift height was established, we have developed a wellhead uplift experimental device, and experiments for the wellhead uplift under different working conditions were conducted. It was found that the increase of wellbore temperature and trap pressure cause the wellhead uplift, the calculation error of model is less than 10% compared with the experimental data. This could be used to predict the wellhead uplift height under different working conditions. It has certain guiding significance for cementing optimization and improvement of the wellhead integrity.

In order to accurately evaluate the fracturing stimulation effect of horizontal wells in shale gas reservoirs, it is suggested to establish a model to predict the temperature distribution in the wellbore of horizontal well and an inversion model of DTS data by using MCMC algorithm, and optimize the production profile interpretation process. In this paper, the characteristics of temperature profile of fractured horizontal wells in shale gas reservoirs were analyzed and the main factors affecting the temperature profile were figured out. Finally, the newly established inversion model was applied to the production profile interpretation of one case well in a certain shale gas reservoir. And the following research results were obtained. First, the temperature profile of fractured horizontal wells is in the shape of irregular “saw tooth”, and each “saw tooth” corresponds to an effective hydraulic fracture with fluid inflow. Second, the longer the fracture is, the greater the wellbore temperature drop at the corresponding fracture location is, and the gas flow rate in the fracture is positively correlated with the temperature drop. Third, from the perspective of influence degree, the factors influencing the temperature profile of fractured horizontal wells in shale gas reservoirs are ranked from the strong to the weak as follows: fracture half-length, gas flow rate, permeability of stimulated area, wellbore diameter, fracture conductivity, horizontal inclination angle, and comprehensive thermal conductivity, among which, the first three are main controlling factors. Fourth, the MCMC inversion method is applied to invert the DST temperature data of the case well. The temperature profile predicted in the model is better accordant with the measured DTS profile, and the absolute error of the predicted temperature at different levels of effective hydraulic fractures is less than 0.02 °C. The interpreted gas flow rate of each fracturing stage is closer to the field measurement, and the deviation of the maximum gas flow rate of a single fracturing stage is only 180.35 m3/d. The absolute error between single-well gas production rate and gas production rate measured at the wellhead is less than 3 m3/d, which proves the reliability of this newly developed inversion model.

We use a 5-h-long experiment with 182 vertical 2-Hz velocity sensors deployed on the surface to characterize noise before and during a hydraulic fracturing monitoring experiment in the Potiguar Basin, NE Brazil. We observe that the seismic noise is mainly from electromagnetic inductions and machinery vibration near the wellhead, and within 2 km of the array center from pumpjacks, pipelines, roads, and industrial facilities. We investigate the origin of the main recorded noise features using amplitude decay analysis and beamforming. We also report resonance composed of a body wave coming from the treatment wellhead area, which is only present when the injection takes place and is most likely associated with body-wave energy coming from the wellhead. To assess the utility of such a data set to retrieve the shallow velocity of the area using ambient noise seismic interferometry (ANSI), different strategies were employed to cross-correlate and stack the data: classical geometrical normalized cross-correlation (CCGN), phase cross-correlation (PCC), linear stacking and time-frequency phase-weighted stacking (tf-PWS). Because of the unsuitable distribution of the noise source and geometry of acquisition, spurious arrivals arise in the correlograms. We propose a simple method to attenuate these unwanted effects, which consists of applying a linear moveout (LMO) correction, stacking the data in the shot domains, and f-k filtering. The correlograms and their correspondent dispersion curves are significantly improved.

The article presents the results of precision hydrogeological monitoring, carried out within the operating iron ore deposit near the city of Gubkin, Belgorod region. The organization of an autonomous instrumentation-measuring complex at the wellhead areas of observation wells is described in detail. The methods of processing the series of synchronous recording of seismic, hydrogeological, and barometric data are considered. The proposed scientific and methodological approach to analyzing the obtained experimental data is oriented towards the background parameters of water-saturated reservoirs of pore and fractured-porous types (including the coefficients of barometric efficiency and tidal sensitivity) and studying the response of the well–aquifer system to mass explosions.

Introduction. Analysis of the projects concerning wellhead protection (WHP) zones delineation shows the majority of the reports to use a simplified calculation. The applied analytical solutions do not refer to the actual geological conditions of the operating water intakes. The lack of distinct guidelines for geological data to be used in the research and the cost increase force the researchers to represent a simplified assessment. Materials and methods. The control of different WHP zone size geological parameters was studied by applying a series of theoretical calculations. Thus, software for analytical modelling of groundwater wells ANSDIMAT developed by the Institute of environmental geoscience, RAS, was used. Delineation of WHP zones is performed by the Particle-Tracking method. Results. Both size and geometry of WHP zones are controlled by several geological and hydrogeological parameters, which entail a synergetic effect. Within the parameters mentioned above, there are such as 1) pumping discharge; 2) aquifer thickness; 3) accessible porosity; 4) flow direction and the hydraulic gradient; 5) hydraulic conductivity; 6) the hydraulic connectivity of an aquitard. Our research shows all six factors perceptibly influence the results. To avoid significant errors each of the factors should be taken into account. Conclusion. Regulations actualization and the Guideline for delineation of wellhead protection zones, in particular, remain to be an area for improvement. Clear requirements for geological and hydrogeological parameter contamination, parameters uncertainty. Contribution: Nikulenkov A.M. — concept and design of the study, collection and processing of materials, writing the text; Yeremin G.B. — concept and design of the study, editing; Noskov S.N. — editing; Mozzhukhina N.A. — writing the text, editing; Wilkina M.V. — collection and processing of materials, writing the text. All authors are responsible for the integrity of all parts of the manuscript and approval of the manuscript final version. Conflict of interest. The authors declare no conflict of interests. Acknowledgment. The study had no sponsorship.

In empty well killing, in order to save the time and cost of killing the well, the dynamic replacement method is often used to kill the well. The main problem of the dynamic replacement method for killing wells is how to avoid terrible working conditions caused by flooding, such as gas carrying fluid, killing fluid being brought to the wellhead. Based on the principle of flooding formation and the basic tenets of flooding correlation experiment and dynamic replacement method, this paper incorporates the kill fluid viscosity, surface tension, droplet diameter, inclination angle, drill pipe joint outer diameter, and drill pipe eccentricity into the calculation range and establishes a new mathematical model suitable for dynamic replacement kill. Based on the calculation results, the influencing factors of flooding are analyzed, and the following conclusions are drawn: the increase of dynamic viscosity, gas density in the well, casing pressure, well angle, the outside diameter of drill pipe, the outer diameter of drill pipe joint, and eccentricity of drill pipe can promote the occurrence of flooding; The increase of surface tension, well-killing fluid density, and casing inner diameter have an obstacle to flooding.

There are abundant natural gas resources in the marine shale gas reservoir of Middle Ordovician Wulalike Formation in the Ordos Basin, which is an important resource base for PetroChina Changqing Oilfield Company to increase the reserves and production of oil and gas. Compared with the other shale gas reservoirs at home and aboard, however, the marine shale gas reservoir of Middle Ordovician Wulalike Formation in the Ordos Basin has a lower formation pressure coefficient and poorer reservoir physical properties and gas-bearing property, so its production increase difficulty is higher. In this paper, horizontal-well volume fracturing was studied and tested based on the earlier vertical well tests. According to the technical idea of the staged multi-cluster massive fracturing of long horizontal section, the propagation mechanisms and morphological characteristics of fractures were studied and analyzed based on the fracturing geological characteristics of the shale gas reservoir in the Ordos Basin. On this basis, a full three-dimensional fracture model was optimally established for parameter optimization. The fracturing of the test well ZP1 was carried out with 15 stages and 103 clusters. After the fracturing, a more complex fracture network was formed with a fracture complexity index of 0.4–0.6. The microseismic monitoring zone is 579 m long and 266 m wide and the fracture is 146 m high. To address the drainage difficulty after large-volume fracturing of low-pressure shale gas in the Ordos Basin, this paper carries out a gas energized fracturing test. Considering the characteristics of reservoir physical properties, gas-bearing property and segmented fractures, 805 m3 liquid nitrogen was injected in stages during the fracturing of the test horizontal well. The formation pressure coefficient measured from pressure buildup data is increased from 0.7 to 0.8 to 1.88. The wellbore gas–liquid flow model was established and the parameters of long-period control-pressure drainage were optimized. The critical surface equipment was upgraded to achieve accurate measurement, safety and environmental protection. And the following research and practice results were obtained. First, based on the technological innovation and optimization, continuous gas–liquid two-phase flow is realized in the test well ZP1 and its production rate and pressure during the test are stable with the tested daily shale gas production at the wellhead of 6.42 × 104 m3. Second, after fracturing, the absolute open flow of the test well reaches 26.4 × 104 m3/d, which is more than 10 times higher than the production rate of the vertical well in the same block during the test. Thus, a significant breakthrough is realized in the exploration of marine shale gas in North China.

Measuring oil production rates of individual wells is important to evaluate a well's performance. Multiphase flow meters (MPFMs) and test separators have been used to estimate well production rates. Due to economic and technical issues with MPFMs, especially for high gas-oil ratio (GOR) reservoirs, the use of a choke formula for estimating well production rate is still popular. The objective of this study is to implement different artificial intelligence (AI) techniques to predict the oil rate through wellhead chokes. Support-vector machine (SVM) and random forests (RF) were used to generate different models to predict the production rates for high GOR and WC wells. A set of data (548 wells) was obtained from oil fields in the Middle East. GOR varied from 1000 to 9351 scf/stb, and WC ranged from 1 to 60%. Around 300 wells were flowing under critical flow conditions, while the rest were subcritical. Hence, two cases were studied using each AI model. Seventy percent of the data was used to train both RF and SVM models, while 30% of the data was used to test and validate these models. The developed RF and SVM models were then compared against the previous empirical formulas. The RF model in both critical and subcritical flow conditions was able to perfectly match the actual oil rates. SVM was able to predict the general trend for the oil rates but missed some of the sharp changes in the oil rate trend. The average absolute percent error (AAPE) values in the subcritical flow for SVM and RF were 1.7 and 0.7%, respectively, while in the critical flow, the AAPE values were 1.4 and 0.75% for SVM and RF models, respectively. SVM and RF models outperform the published formulas by 34%. The results from this study will help to estimate the real-time oil and gas rates based on the available data from wellhead chokes without the need for field intervention.

By simultaneous solution of the equation of inflow of a gas–condensate mixture in the formation and in the tube and with account taken of the phase states of the gas–condensate mixture, the author has implemented a calculation procedure that makes it possible to predict, from wellhead data, the pressure at the wellbore and the formation pressure, and also other technological indices of development of deep-seated gas–condensate reservoirs in a depletion regime. Within the limits of the considered initial data, the author has modeled the process of inflow of the gas–condensate mixture to a partially penetrating well in a homogeneous anisotropic formation and has established the regularities of influence of the site of drilling-in and the degree of imperfection of the accumulation of a retrograde condensate in near-wellbore zones with time.

This article describes the development of a well design for dual completion (DC) of multi-layer deposits in order to accelerate the development and increase oil production with the introduction of new technologies and highly efficient equipment. Calculations were made for the development of a well design for DC from the two-year operation of three large horizons, consisting of 7-9 productive layers. As a result, it was determined that the resulting large inflow of oil during the development of these wells proves the success of drilling operations in this area, proving that it is reasonable to choose the right design for dual completion operation of wells., {"references":["1.\tМетодические указания по выбору конструкций нефтяных и газовых скважин, проектируемых для бурения разведочных и эксплуатационных на площадях - Москва Миннефтепром, 1973.","2.\tДеряев. А.Р., Гулатаров Х.Г., Эседуллаев Р., Аманом М. Технология бурения наклонно-направленных и горизонтальных скважин и расчеты их проектирования // (научная монография) Ашгабат: Ылым, 2020. – 608 с.","3.\tА.Г. Калинин. Бурение нефтяных и газовых скважин, - Москва ЦентрЛитНефтеГаз 2008.","4.\tА.Р. Деряев. Разработка конструкции скважин для метода одновременно-раздельной эксплуатации нескольких нефтяных пластов. «Наука и техника в Туркменистане». №6. 2013. С. 71-77."]}

Dual-gradient drilling technology is being increasingly used in formations with narrow pressure margins. For dual-gradient drilling based on downhole separation, hollow spheres are separated into the annulus at the separator position, resulting in variable mass flow in the wellbore. Thus, existing heat transfer models are no longer suitable for describing wellbore temperature profiles in dual-gradient drilling. This study focused on developing a wellbore heat transfer model that fully considers separated hollow spheres entering the annulus, complex casing programs, and heat sources, for dual-gradient drilling based on downhole separation. The model was solved using an iterative method. Then, the accuracy of the model was verified using temperature data measured from two wells. Finally, the difference in the annular temperature distributions between dual-gradient drilling and conventional single-gradient drilling were investigated, as were the wellbore heat transfer characteristics for dual-gradient drilling. The following major conclusions were drawn: (1) for dual-gradient drilling based on downhole separation, at the separator location, the annular fluid temperature does not decrease, but rather increase in the flow direction because of the inflow of hollow spheres; (2) a clear inflection point exists in the annular fluid temperature curve at the location where the separator would be; (3) the magnitude of the mutation of the temperature curve at the inflection point is considerably affected by the heat capacities of the hollow spheres and the pure drilling fluid; (4) under the same change in separation efficiency, distance between the bit and separator, flow rate, and thermal conductivity of formation, the variation range of the fluid temperature at the bottom hole is greater than that at the wellhead.

In order to reduce the non production time of drilling, improve the efficiency and safety of drilling, improve the economic effect of managed pressure drilling (MPD), and realize the intelligent control construction of digital oilfield. Based on the pressure control in MPD, this paper analyzes the pressure control drilling system, takes the wellhead back pressure as the controlled parameter, calculates the mathematical model of the throttle valve according to the characteristics of the throttle valve, the basic parameters and boundary conditions of pressure control drilling, and puts forward an improved particle swarm Optimization PID neural network (IPSO-PIDNN) model. By means of remote communication, VR technology can realize remote control of field control equipment. The real-time control results of IPSO-PIDNN are compared with those of traditional PID neural network (PIDNN) and traditional Particle Swarm Optimization PID neural network (PSO-PIDNN). The results show that IPSO-PIDNN model has good self-learning characteristics, high optimization quality, high control accuracy, no overshoot, fast response and short regulation time. Thus, the advanced automatic control of bottom hole pressure in the process of MPD is realized, which provides technical guarantee for the well control safety of MPD.

In the case of assembly wellhead, a spacer spools was used to provide space and connect between parts of the wellhead. In order to design spacer spool with specified material should comply the standards and procedures of the oil and gas industry. The results of the material calculation were using the ASME BPVC guidelines. These three materials strengths were calculated if used as a body spacer spool. Based on acceptance criteria on API 6A 21st Edition, these three materials were categorized as acceptable to be used as a body spacer spool for this specification. These three materials strengths were also calculated the stress of the flange and flange rigidity criteria. Based on the acceptance criteria on ASME BPVC guidelines, the results showed that these materials can be used for flange because it had stress value under yield strength of material which was flange rigidity criteria for operating condition has 0.59 and 0.66 for testing condition because had value of rigidity that met with minimum acceptance criteria.

The long gestation period, high upfront costs and the risks in the development of central geothermal power plants are the main reasons for the slow rate of geothermal electricity growth and its contribution to the global electricity mix. The overall objective of this study was to make a comparison between central geothermal power plants and wellhead power plants in the delivery of geothermal electricity projects. The study showed that wellhead power plants are generally less efficient compared to central power plants because of higher specific steam consumption, but are financially attractive because of the quicker return on investment, early electricity generation and the lower financial risks. The study showed that permanent wellhead power plants are a better option for geothermal wells with too low or too high steam pressure compared to others in the steam field. Temporary use of wellhead power plants as opposed to their permanent use is preferred when only limited time is available between the commissioning of a wellhead plant and the commissioning of a central power plant in the same steam field. Technical, operational and environmental challenges, including higher specific steam consumption and lower efficiency than central power plants as well as absence of geothermal fluid reinjection system make wellhead plants less economical and less sustainable in resource use. It can thus be concluded that wellhead power plants can reduce the long wait to generate geothermal electricity and make an early return on investment for investors. Both central and wellhead power plants have relatively higher capacity factor than many other power plants and so can be used to supply base load electricity for the grid or off-grid power supply. This study is a review of the central and wellhead power plants and additionally provides policy guidelines in the execution of geothermal electricity projects either as central or wellhead power plants for grid electricity generation.

The characterization of the multiphase flow through valves and orifices is a problem yet to be solved in engineering design, and there is a need for a prediction model able to simulate the complexity of this kind of flow in relation to fluid thermodynamic behaviour, and applicable to different incoming stream conditions and compositions. The present paper describes the development of a global model for the calculation of the discharge coefficient of orifices and choke valves operating under two- and three-phase flow as well as critical and subcritical conditions. The model generalizes the hydrovalve model developed by Selmer-Olsen et al. (in: Wilson (ed) Proceedings of 7th international conference on Multiphase Production, BHR Group, pp 441–446, 1995) and the Henry–Fauske (J Heat Transfer 93: 179–187, 1971. 10.1115/1.3449782) non-equilibrium model on the basis of an updated definition of the discharge coefficient. The model has been adapted to real choke valve geometries, by fitting the discharge coefficient and model parameters using field data from three production wells. The model developed is a global quartic function with different constants for the different valve geometries. The new discharge coefficient allows to simulate field data with high accuracy.

Two-phase flow rate estimation of liquid and gas flow through wellhead chokes is essential for determining and monitoring production performance from oil and gas reservoirs at specific well locations. Liquid flow rate (QL) tends to be nonlinearly related to these influencing variables, making empirical correlations unreliable for predictions applied to different reservoir conditions and favoring machine learning (ML) algorithms for that purpose. Recent advances in deep learning (DL) algorithms make them useful for predicting wellhead choke flow rates for large field datasets and suitable for wider application once trained. DL has not previously been applied to predict QL from a large oil field. In this study, 7245 multi-well data records from Sorush oil field are used to compare the QL prediction performance of traditional empirical, ML and DL algorithms based on four influencing variables: choke size (D64), wellhead pressure (Pwh), oil specific gravity (γo) and gas–liquid ratio (GLR). The prevailing flow regime for the wells evaluated is critical flow. The DL algorithm substantially outperforms the other algorithms considered in terms of QL prediction accuracy. The DL algorithm predicts QL for the testing subset with a root-mean-squared error (RMSE) of 196 STB/day and coefficient of determination (R2) of 0.9969 for Sorush dataset. The QL prediction accuracy of the models evaluated for this dataset can be arranged in the descending order: DL > DT > RF > ANN > SVR > Pilehvari > Baxendell > Ros > Glbert > Achong. Analysis reveals that input variable GLR has the greatest, whereas input variable D64 has the least relative influence on dependent variable QL.

By reviewing the development history of stimulation techniques for deep/ultra-deep oil and gas reservoirs, the new progress in this field in China and abroad has been summed up, including deeper understanding on formation mechanisms of fracture network in deep/ultra-deep oil and gas reservoir, performance improvement of fracturing fluid materials, fine stratification of ultra-deep vertical wells, and mature staged multi-cluster fracturing technique for ultra-deep and highly deviated wells/horizontal wells. In light of the exploration and development trend of ultra-deep oil and gas reservoirs in China, the requirements and technical difficulties in ultra-deep oil and gas reservoir stimulation are discussed: (1) The research and application of integrated geological engineering technology is difficult. (2) The requirements on fracturing materials for stimulation are high. (3) It is difficult to further improve the production in vertical profile of the ultra-deep and hugely thick reservoirs. (4) The requirements on tools and supporting high-pressure equipment on the ground for stimulation are high. (5) It is difficult to achieve efficient stimulation of ultra-deep, high-temperature and high-pressure wells. (6) It is difficult to monitor directly the reservoir stimulation and evaluate the stimulation effect accurately after stimulation. In line with the complex geological characteristics of ultra-deep oil and gas reservoirs in China, seven technical development directions are proposed: (1) To establish systematic new techniques for basic research and evaluation experiments; (2) to strengthen geological research and improve the operational mechanism of integrating geological research and engineering operation; (3) to develop high-efficiency fracturing materials for ultra-deep reservoirs; (4) to research separated layer fracturing technology for ultra-deep and hugely thick reservoirs; (5) to explore fracture-control stimulation technology for ultra-deep horizontal well; (6) to develop direct monitoring technology for hydraulic fractures in ultra-deep oil and gas reservoirs; (7) to develop downhole fracturing tools with high temperature and high pressure tolerance and supporting wellhead equipment able to withstand high pressure.

Oil and gas mixed transportation is an important technology in oil and gas production. Multiphase fluid is transported from the wellhead to the floating platform through a riser system. Based on computational fluid dynamics, a numerical model of multiphase flow in a deepwater riser by considering hydrate phase transformation and sand production was established, which was then solved by the finite-difference method. The results show that under constant inlet pressure, the pressure drop decreases with increasing gas–liquid two-phase flow rate, and increases with increasing sand production rate. Furthermore, the hydrate phase transition decreases the pressure. The effect of liquid on the temperature in the riser is apparent: the heat transfer between the fluid and seawater is mitigated by the insulation layer, thus raising the critical point of the hydrate phase transition. Finally, the velocity and volume fraction of the gas phase increase from the inlet to the outlet of the riser. At the same time, the velocity of the liquid–solid phase increases, whereas the volume fraction decreases.

Influenced by the low temperature of seawater, non-equilibrium formation of natural gas hydrate (hereinafter referred to as hydrate) in the wellbore of a gas/water-producing well is prominent, which increases the risks of safety, such as wellbore blockage. In this paper, a wellbore temperature and pressure distribution model and a theoretical model of non-equilibrium hydrate formation and decomposition in marine gas/water-producing wells in the production process of water-bearing natural gas were established on the basis of the previously established methane hydrate phase equilibrium model and hydrate formation and decomposition dynamics model. Then, numerical simulation calculation was carried out on the basis of finite difference method, and thus a set of risk prediction method for the non-equilibrium hydrate formation (hereinafter referred to as hydrate formation risk prediction method) suitable for the production process of marine gas/water-producing well was developed. On this basis, the reliability of the prediction method was verified by using the data of one certain onshore gas production well LN-X, and then the non-equilibrium hydrate formation and decomposition laws in the wellbore of marine gas/water-producing wells under the influences of different parameters were studied. And the following research results were obtained. First, with the increase of daily gas production or water cut, both the hydrate formation area in the wellbore and the amount of hydrate substances decrease. As a result, wellbore blockage is less likely to happen, which is more favorable for the safe production of marine gas/water-producing wells. Second, the higher the wellhead tubing pressure is, the larger the hydrate formation area in the wellbore is and the greater the amount of hydrate substance is. As a result, the wellbore is blocked more easily, which is more unfavorable for the safe production of marine gas/water-producing wells. Third, even under different sea surface temperatures, the range of hydrate formation area is consistent, and so is the range of hydrate decomposition area. The amount of hydrate substance is only different near the wellhead. The higher the sea surface temperature, the lower the amount of hydrate substance. In conclusion, the proposed hydrate formation risk prediction method is reliable, and the research results can provide theoretical guidance for the safe production management of offshore gas reservoirs.

In the last decade, the monitoring systems have become a crucial component for the drilling and oil wellhead operations. The importance of such systems has been magnified by oil companies and the regulatory bodies after the Gulf of Mexico incident on Deepwater Horizon rig that took place on 20th of April 2010 in which eleven crewmen were killed. The data obtained by the monitoring systems can provide significant advisory data to assist the operators to mitigate the various risks during the operations and to reduce the maintenance cost of equipment. In this paper, an overview of recent studies on the existing monitoring systems for the drilling and oil wellhead operations technical challenges faced by operators and the benefits of monitoring systems has been presented......

This project uses production data to generate well-specific correlations for GLR, BSW and sand concentration which are used for predictions. A software has been developed to effect a smart control algorithm. This results in a bean up or bean down operation depending on the current flowing conditions and constraints. Excel programming environment was used to write a code that constantly takes in measured data points, models the behavior of the individual data sets with bean size and controls the choke if the parameters of interest go above a predetermined cut-off. The software was also equipped with an inverse matrix solving algorithm that enables it to determine the choke performance constants for any set of initialization data. A set of data from field X were supplied and the choke performance constants; A, B, C, D and E, were found to be 10, 0.546, 0.0, 1.89 and 1.0 respectively. In addition to that, data from subsequent production operations were entered and the software was able to control the choke size to ensure that production stays below set constraints of 500, 80 and 10 in field units for GLR, BSW and sand concentration respectively. From this, it can be concluded that the software can effectively maintain the production of unwanted well effluents below their cut-offs, thereby improving oil production and the overall Net Profit Value (NPV) of a project.

In the gas drilling design, accurate prediction of wellbore temperature profile is very crucial. Different from liquid drilling fluid, physical and thermophysical parameters of gases are sensitive to the change of pressure and temperature, at the same time, the change of these parameters will react against the wellbore temperature and pressure. Based on the energy conservation principle, a temperature-pressure coupling calculation model was established to predict the gas temperature profile during gas drilling process. The model is solved by cycle coupling iteration method. The calculation shows that annular temperature rises sharply near the wellhead, drops sharply at bottom hole and is a little higher than the formation temperature in other places. Without considering the influence of friction heat, calculated temperature is lower than the actual temperature. Temperature trends are the same under different pump rates and larger pump rate leads to larger temperature range at the wellhead and at bottom hole. Compared with the pump rate, bit nozzle size has more influence on the temperature drop range. Temperature reduction increases from 31.3-57.2? while bit nozzle size decreases from 539-339 mm2.

In oil and gas production in deep-water high-pressure–high-temperature (HP–HT) wells, wellhead uplift may cause the seal failure of wellbore integrity. Aiming at the oil and gas production stage in deep-water HP–HT wells, we considered the influence of cement sheath cementation and developed a model for calculating the height of wellhead uplifts, and simulation experiments for wellhead uplifts were carried out under the condition of the double pipe string at different cement return heights and multilayer pipe string coupling cementing and noncementing based on a self-developed HP–HT wellhead uplift simulation device. The results show that the elongation of the double pipe string under the condition of a cement return height of 100% is reduced significantly compared with that under the condition of a cement return height of 50%. Also, the maximum elongation of the multilayer pipe string under the condition of coupling and cementing is significantly reduced compared with that under the condition of noncementing. These show that cement sealing has a binding effect on wellhead uplifts. The error between the calculated and the experimental results is less than 10%; thus, the model can be used to predict the wellhead uplift height under different working conditions and provide technical guidance for designing scientific measures to prevent wellhead uplifts.

The major functions of the subsea Christmas tree include production management, wellhead pressure control, chemical reagent injection, and oil/gas production safety control. It is necessary to investigate the reliability and safety of the tree for safe and stable operation of subsea production systems. A fault tree and a dynamic Bayesian model are used to assess reliability and safety and to consider the time slice-based characteristics of the reliability. Using the control variable method, impact analysis is performed to quantify the impact of each failure rate on the system and sort the impacts of failure modes on reliability and safety. Finally, failure prediction is performed. The results show that the annulus loop has the lowest reliability and is the most likely to fail. The failure rate of the tubing hanger has the biggest impact on system reliability, while the failure rate of the choke valve has the biggest impact on system safety. When the tree fails, the failure probabilities of the tubing hanger and the valve group of the production loop are relatively high. On the basis of the above results, corresponding control measures are proposed that can significantly reduce the failure risk of the tree.

High-temperature tensile tests at 25, 150, 250, and 350°C were carried out on 30CrMo, 42CrMo, 1Cr13, and 304 steels. The changes in tensile strength, yield strength, elongation, and area reduction ratio with temperature were determined. By analyzing the fracture morphology and the relationship between strength and hardness, the influence of high-temperature mechanical properties on crack sensitivity and the mechanism of crack formation is discussed. Experimental results indicated that both the tensile and yield strengths of the four steels gradually decrease with the increase in temperature. The yield ratios of 30CrMo, 42CrMo, 1Cr13, and 304 steels are, respectively, 0.71–0.77, 0.79–0.86, 0.84–0.88, and 0.33–0.40 which shows that among the four steels, 304 has the best ductility, while 1Cr13 has the worst ductility. As for the four steels, the values of reduction ratio of area are greater than 60%, except for 42CrMo which is slightly lower than 60% at 150 and 250°C, indicating that the four steels have low crack sensitivity within the test temperature range. Ductile fracture is the main fracture mechanism for 30CrMo, 42CrMo, and 304 steel, whereas brittle fracture is predominant for 1Cr13. There is a linear regression relationship between the strength and hardness at different temperatures. The obtained linear regression relationship can be used to predict and estimate the strength of 30CrMo, 42CrMo, 1Cr13, and 304 steels at different temperatures according to the hardness results.

One of the most promising ways to improve the efficiency of mechanized oil production is a plunger pump with a submersible drive, which allows obtaining harmonic reciprocating movement of the plunger. In the pumping process of well products by plunger pumps, oscillations in the velocity and pressure of the liquid in the lifting pipes occur, which lead to an increase in cyclic variable loads on the plunger, a decrease in the drive life period and the efficiency of the pumping unit. To eliminate the pulsation characteristics of the plunger pump and increase the reliability indicators of the pumping unit (in particular, the overhaul period), pneumatic compensators can be used. A method for calculating the optimal technological parameters of a system of deep pneumatic compensators for plunger pumping units with a submersible drive, based on mathematical modeling of hydrodynamic processes in pipes, has been developed. Calculations of the forming flow velocity and pressure in the lifting pipes of submersible plunger units equipped with pneumatic compensators (PC) have been carried out. Influence of the PC technological parameters on the efficiency of smoothing the oscillations of velocity and pressure in the pipes has been analyzed. Non-linear influence of the charging pressure and PC total volume on the efficiency of their work has been established. Optimal pressure of PC charging, corresponding to the minimum pressure in the tubing during the pumping cycle for the considered section of the tubing, is substantiated. Two ultimate options of PC system placement along the lifting pipes are considered. In the first option, PC are placed sequentially directly at the outlet of the plunger pump, in the second - evenly along the lift. It is shown that the first option provides the minimum amplitude of pressure oscillations at the lower end of the tubing and, accordingly, variable loads on the pump plunger. Nature of the pressure and flow velocity oscillations in the tubing at the wellhead for both options of PC placement has similar values.

Based on the research of the formation mechanism and evolution rule of hydrate flow obstacle during deep-water gas well testing, a new method for the prevention of hydrate flow obstacle based on safety testing window is proposed by changing the previous idea of “preventing formation” to the idea of “allowing formation, preventing plugging”. The results show that the effective inner diameter of the testing tubing and the wellhead pressure decrease gradually with the formation and precipitation of hydrates during deep-water gas well testing, and it presents three typical processes of slow, fast and sudden changes. There is a safety testing window during deep-water gas well testing. The safety testing window of deep-water gas well testing decreases first and then increases with the increase of gas production rate, and increases with the increase of hydrate inhibitor concentrations. In the case with different testing production rates, a reasonable testing order with alternate low and high gas production rates has been proposed to further reduce the dosage of hydrate inhibitor and even avoid the use of hydrate inhibitors considering the decomposition and fall-off of hydrates. Compared with the traditional methods, the new method based on safety testing window can reduce the dosage of hydrate inhibitor by more than 50%.

The occurrence of elevated temperatures within landfills is a challenging issue for landfill operators to detect and correct. Little is known regarding the causes of elevated temperatures (ETs) or the number of landfills currently operating under such conditions. Therefore, the goal of this research was to determine which landfills within Florida have been impacted by ETs, and to develop a more complete understanding of the factors that may lead to these landfills becoming elevated temperature landfills (ETLFs). Historical landfill gas wellhead data, waste deposition reports, and landfill site geometry were collected for 27 landfill cells through the Florida Department of Environmental Protection electronic document management system, OCULUS database and from landfill operators and owners. These data were evaluated to quantify the characteristics that result in landfills having ‘elevated’ temperatures. Gas data included landfill gas temperatures and methane, carbon dioxide, and balance gas content. Furthermore, landfill maps were created in ArcGIS to observe spatial distribution of ETs in landfills over time. Upon analysis of the landfill gas wellhead data, it was discovered that 74% of studied landfill cells had ET readings; regulatory limits specify a maximum allowable gas temperature of 55 °C (131 °F). It was discovered that 37% of landfill cells contained MSW ash; of these cells, 90% of them are considered ETLFs. ETLF cells are on-average double the site area and approximately 6 m deeper than the average non-ETLF cell. Furthermore, results suggest that heat propagation in most landfills is limited; however, heat propagation is possible if gas wells are turned off for an extended time period.

Productivity of wells in South-West Iran has decreased due to completion and production problems in recent decades. This is a large risk against sustainable production from the fields. To allow stable production, an important measure is completion and production optimization including artificial lift methods. This was investigated using simulations validated by pilot field tests. Several case studies were considered in terms of their completion and production. Five scenarios were investigated: natural production through annulus and tubing (scenario-1 and 2), artificial gas lift production through annulus (scenario-3), through tubing using non-standard gas lift (scenario-4) and using standard gas lift (scenario-5). Scenario-1 is currently the case in most wells of the field. To find the optimal scenario and completion/production parameters, simulations of 11 wells of an oilfield in the region were carried out using nodal and sensitivity analysis. The optimized parameters include wellhead pressures (WHPs), tubing dimensions, maximum tolerable water cuts and gas oil ratios and artificial gas injection rate. Simulation results were validated by pilot field tests. In addition, appropriately selected wellhead and Christmas trees for all scenarios were depicted. Simulations confirmed by field pilot tests showed that optimization of completion and production mode and parameters can contribute largely to production improvement. The results showed that the current scenario-1 is the worst of all. However, production through tubing (scenario-2) is optimal for wells which can produce with natural reservoir pressure, with an increase of 800 STB/Day rate per well compared with scenario-1. However, for wells requiring artificial gas lift, the average production rate increase (per well) from the annulus to tubing production was 1185 STB/Day. Next, using the standard gas lift (scenario-5) was found to be the optimal mode of gas lifting and is strongly recommended. WHPs in scenario-5 were the greatest of all, whereas scenario-1 gave the lowest WHPs. The optimal tubing diameter and length were determined. The greatest maximum tolerable water cut was obtained using scenario-5, whereas the lowest was with scenario-1. The maximum tolerable GOR was around 1900 scf/STB. Changing of scenarios did not have significant effect on maximum tolerable GOR. The optimal artificial gas injection rates were found. This validated simulation work proved that completion and production optimization of mode and parameters had considerable contribution to production improvement in South-West Iran. This sequential comprehensive work can be applied in any other field or region.

Gob ventilation boreholes (GVBs) are widely used for degasification in U.S. longwall coal mines. Depending on geological conditions, 30–50% of methane can be recovered from longwall gob using GVBs. A NIOSH funded research at the Colorado School of Mines confirmed that GVBs can efficiently reduce methane at the face. However, GVBs can also draw some fresh air from the face and create explosive gas zones (EGZs). Explosive gas mixtures may be formed in gob areas due to the increased ingress of oxygen from GVBs. It is critical to identify the locations for GVBs for maximizing extraction of methane and minimizing hazards of explosion. This study analyzes the effect of operating parameters and design of GVB on methane extraction, EGZs formation, and face and tailgate methane concentrations. Methane extraction, formation of EGZs, and concentration of methane in working areas are significantly impacted by various factors. These factors include the distance of work face and tailgate from GVBs, diameter of GVBs, vacuum pressure of wellhead, GVB distance from the roof of the coal seam, and number of operating GVBs in a panel. Computational fluid dynamics (CFD) evaluations suggest optimal design and operating parameters of GVBs that can contribute to maximum benefits with minimum risks.

The storage of natural gas in underground reservoirs is an important component of the overall natural gas delivery infrastructure because it permits better management of the supply and demand cycles. Leakage of natural gas to the outside can lead to severe safety and environmental consequences. An integrated Bow-tie (BT) and Bayesian Network (BN) model to assess the probability of gas release is presented in this paper. A barrier-based risk management approach, incorporated in the BT model, provides a useful visualization of the operational hazards and their safe management. The BT approach involves the identification of hazards (or threats) leading to a top event, such as release of natural gas to the external environment. Each hazard has several associated barriers that can either prevent the occurrence of the top event or mitigate the consequences. BT models were constructed for well head and sub-surface systems. However, the BT approach does not consider the interactions between different hazards and barriers. Furthermore, the degradation of the barrier effectiveness over time and space is typically not quantified. BN models were constructed to quantify the failure probabilities of the barriers identified by BT. The BN models compute the probabilities of failure of the wellhead and sub-surface systems. Sensitivity and value of information analyses were conducted using the BN model.

In this paper, the casing strings of cement slurry during the curing period are taken as the research object in order to build a force model, with comprehensively considering the influence factors such as the phase transition heat transfer and volume change of the cement slurry during the curing period. The random contacts between casings and well walls were simulated by establishing a gap element between two phases of cement slurry. Formulas of axial loadings on the casings during curing of cement slurry were obtained using the finite element method. With this method and on-site measurement, the wellhead axial loads of three wells during cement slurry curing were calculated and tested. The results revealed that the maximum relative deviation between the theoretical prediction results by the model and the actual field test data was 10.42%, indicating that the model established is reliable. Finally, using the established finite element calculation method, the effects of the cementing section length on extra loadings on the wellhead were analyzed. This study serves as an accurate reference to calculations of extra loadings on the wellhead during curing of cement slurry and optimization of cementing section length, thus facilitating well cementation.

Based on the study of the geological background, it is considered that the main factors affecting helium enrichment in the northern margin of the Qaidam Basin (NMQB) are widely distributed rock masses, developed fractures, groundwater system, and more. Among these factors, the rock masses provide sufficient helium gas source, while the fractures and the groundwater system provide good natural gas migration channels and carriers. 4He, 20Ne, and other rare gas isotopes have a good linear relationship, which proves that the groundwater system plays a vital role in the helium enrichment process, and helium flux is high. Based on the theoretical understanding of helium reservoir formation formed by helium investigation in the Weihe Basin and its adjacent areas, it is predicted that the NMQB has the prospect of crustal helium resources. Through the analysis of natural gas wellhead samples in the helium prospective areas of the Mabei and Dongping gas fields in this area, it is found that the helium content is generally high. Isotope analysis shows that helium in this area is typically crust sourced. Furthermore, 21 out of the 22 source helium samples analyzed in this paper meet or exceed the industrial standard. According to the average helium gas volume fraction of sixteen samples in the Mabei area of 0.28%, Mabei area alone can become an extensive helium resource prospective area. Through further investigation and evaluation, it is expected to obtain super large helium reserves in the study area.

There have been reports of municipal solid waste landfills with waste and gas wellhead temperatures of at least 80–100 °C, which is in excess of temperatures reported at typical landfills. Landfill...

The offshore oil and gas industry began in 1947 when Kerr-McGee completed the first “out of the land” well successfully in the Gulf of Mexico off the coast of Louisiana in just 4.6 m of water. Offshore exploration and production technology have been gradually expanded in the decades since, and the venture for finding oil has moved to deep water areas. Subsea valves are mainly located on the wellhead and manifolds and could be ball, through conduit gate and axial check valves. This paper introduces the main types of subsea valves as well as their main components. The suitable materials for different components have been proposed to increase the reliability through mitigating the corrosion risk, improving the mechanical strength, compatibility with the fluid, maintaining the safe operation of the valve over the design life, etc. The proposed materials are used for critical components of the valves such as body, bonnet, disk, seats, pup piece, etc. and the best choices have been summarized at the end of the table. A chart has been developed introducing the key parameters in selecting the optimized material choice for subsea valves such as erosion, corrosion, HSE, process compatibility, etc.