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Liquid unloading is a very common and important issue in horizontal gas wells, and the presence of curve sections increases the complexity of the phenomenon and its study. Liquid loading in a gas well will sharply reduce production, therefore, the liquid-unloading onset of different curved pipes is essential to gas production. In this work, liquid-unloading onset experiments were conducted in curved pipes with different curvatures. Then, the critical gas velocityVsgCRcan be determined according to the measured pressure gradients, liquid holdup, and liquid film reversal. This work analyzes the factors which will lead to the liquid unloading and explores the trend of the pipe curvature’s influence on the liquid unloading under laboratory conditions. The experimental results show that the critical gas velocity rises with the increase of pipe curvature, the increase is mainly due to the centrifugal force. The present work also compares the predicted results of the OLGA model and Beggs–Brill model with experimental data. The comparison results indicate that both models fit relatively well to the experimental data at the low superficial gas velocity, and both models have poor performance at high superficial gas velocity. The OLGA model fits the experimental data better than the Beggs–Brill model at high superficial gas velocity. The error analysis shows that most of the predicted data is not in good agreement with experimental data. Some errors between experimental data and calculation results are out of the range of 50%.

The coal fine output from coalbed methane (CBM) formation during the production of CBM wells seems to be a common occurrence. At the lower section of wellbore, the aggregation of coal fine particles may occur, that lead to the increase of local coal fine concentration and the negative effect on the work of downhole equipment. To investigate the migration of coal fine particles in gas-liquid flow, the gas-liquid-solid three-phase flow experiments were carried out. The experiments were conducted in a downbent V-shaped pipe with different incline angles (5°, 15° and 25°), and recorded the real-time liquid holdup at certain positions of the lower elbow with the conductivity method. The terrain-induced slugs can be identified on the time series curves of liquid holdup. And the characteristic parameters of each slug, such as slug length and translational velocity, were calculated. By injecting marked coal fine particles into the multiphase flow loop and observing whether they can be discharged from the V-shaped pipe, the lower limits of gas and liquid velocities to void the particle retention at the lower elbow were collected. According to the experimental observation of the coal fine particle movement in one slug unit, we defined dimensionless particle velocity function FD to analyze the particle transport mechanism in the terrain slug flow. The FD value distribution of terrain slugs, calculated by the use of slug parameters, changed with the slug dissipation and coalescence in the experimental incline pipeline. Detail analyses of FD statistical parameters show that the mean values of FD increase with the rise of mixture flow velocity, and the decrease of inclination angle. The mean values of FD at the critical particle discharge conditions are positively correlated to particle concentration. And a linear relationship between the critical means of FD and the particle concentrations is presented.

Natural gas is a clean fossil energy and an important sector in the energy consumption chart. Because of its reliability and low carbon-hydrogen ratio, the demand for natural gas increases steadily to replace coal and wood to better protect environment. To accommodate the ever rising in natural gas production and transportation, more gas pipelines are being constructed. Meanwhile, the existing gas pipelines are aging inevitably. One of the critical needs in natural gas flow assurance is detecting and locating pipeline leak in a timely manner. A reliable and timely detection of the leakage of gas pipeline can not only reduce the loss of hydrocarbon, but also limit the damage to facilities, possible loss of life, and the extent of environmental pollution. Two or more leakage points in a pipeline were observed in the field. Physical methods and mathematical models were employed to detect pipeline leakages. However, literature review indicates that no mathematical model has been developed to detect multiple leaks in the same pipeline. This study focused on the detection of two leak points in a pipeline. Multi-flowrate tests are proposed to evaluate the locations and sizes of leakages in two leak points. The new mathematical model is crucial when no physical inspection is available. The proposed model can be used to monitor possible leak in real-time because flowrate and pressure that are utilized to estimate multiple leaks are monitored in real-time and are available almost simultaneously. Therefore, the new method provides a practical, quick, and low computational cost approach to detect multiple leakages. The proposed method is important because existing mathematical models assumed single leak in a pipeline, which limits their applications because the detection will be misleading if there is more than one leakage in the same pipeline. The proposed model can differentiate single-leakage scenario from multi-leakage scenario based on multi-rate tests. The identification is critical because it guides the leakage detection to the right direction.

The tight reservoirs have been successfully developed by horizontal wells with massive hydraulic fractures. The inherent heterogeneity along the wellbore, complex fracture networks generated due to the pre-existing natural fracture and stress isotropy, the difference of reservoir properties between the stimulated reservoir volume (SRV) and the unstimulated region all bring huge challenges in predicting pressure and rate transient responses. Previous study always simplified the whole reservoir as homogeneous or radial composite region, and treated the complex networks as orthogonal fracture networks. In the light of this situation, by using the source function, boundary element method and composite reservoir model, a rigorous semi-analytical model for a horizontal well with complex fracture networks in heterogeneous reservoirs was presented in this paper. A previous semi-analytical model and numerical model established by commercial simulator were both used to verify the feasibility of the proposed model. The effects of critical parameters on the transient pressure behaviors are discussed. The results show that heterogeneity of the reservoir has a significant influence on pressure behavior. The sensitivity analysis of fracture number, fracture geometry, storage coefficient and inter-porosity factor of SRV, reservoir sizes and relative position between SRV and the outer boundaries are conducted to further understand the transient pressure behaviors of volume fractured horizontal well. In this paper, both the heterogeneity along the horizontal well in the SRV and the heterogeneity between the SRV and the unstimulated region is brought into consideration. In addition, the complex fracture geometry is also captured. Therefore, our model can be capable of studying the transient pressure behaviors of volume fractured horizontal wells in heterogeneous reservoir. The research results provided by this work have some significance for well test interpretation of tight reservoirs.

Nowadays, unloading gas wells with coiled tubing is a common application to the field. However, it still lacks of adequate understanding of dynamic behavior of the unloading process. This paper investigates the process of liquid unloading by gas lift with coiled tubing under transient conditions. This unloading process can be divided into three stages: liquid rising in tubing, liquid slug production, and liquid production by entrainment. In each stage, the mass and conversation equations are applied as governing equations. The components of each stage include coiled tubing, coiled tubing-tubing annulus, liquid slug, gas bubble, and liquid film. Empirical correlations have been used for surface gas injection choke, check valve, friction factor, the relationship between the gas bubble and the liquid slug velocity, inflow performance relationship, and black oil fluid properties. From the above, the dynamic model coupling real-time change of inflow performance relationship is developed. The lower upper (LU) factorization and Euler's method are applied to solve the proposed dynamic model in time domain. Among all these variables, the most important ones include gas injection rates, pressures at various locations, length of the liquid slug and gas bubble, and phase velocities. Through the simulation efforts, the mechanism of liquid unloading process is revealed. Gas lift is commonly constrained by gas availability. This is a pioneering study on liquid unloading with coiled tubing. The results can be applied to design coiled tubing gas lift to optimize the usage of injected gas, choose appropriate pump, and save the energy consumed in gas lift operation.

The free gas evolved in the pump chamber results in a low rod pump working efficiency, and it can even lead to a failure. A common and effective solution is to install a downhole gas separator before fluid entering the chamber, which can divert the free gas to the annulus. If we can re-inject the diverted gas back to the tubing at a shallower depth above the pump, the flowing gas is then re-combined with the liquid and decreases fluid density. Consequently, the injected gas also creates additional lifting drive for the liquid. A new technology based on this concept has been developed and called Casing Gas Assisted Rod Pumping (CGARP). This paper firstly presents an analytical model to optimize the overall lifting performance and minimize the operating expenditure. It is especially useful in producing hydrocarbon at high GOR. As the gas is re-combined with the liquid above the pump installation depth, the hydrostatic pressure gradient is reduced consequently. However, if the gas reinjection valve is placed at a shallow depth, the well segment at reduced fluid density is subsequently short, so the contribution of gas lift is restricted. Vice versa, if the gas reinjection valve is placed at the depth close to the pump, it requires high pressure to open the gas injection valve, so the gas reinjection can happen infrequently and the production rate is unsfplease. This paper has proposed a genetic optimization method to maximize the overall production system efficiency. A multi-variable vector has been defined, which includes pumping speed and depth, mechanical power, rod string diameter and length, surface stroke length, downhole separator efficiency, as well as gas reinjection valve depth. The optimized object can be the system lifting efficiency or Net Present Value, which must be a function of this vector in the constraint of mass and momentum conservations. This work has been applied as the primary guide for four oil producers with rod pump installed in Jilin field, China. The average system lifting efficiency and production rate have been increased by 20% and 15% respectively. This analytical model has enhanced the field performance. Most importantly, the same concept can be applied for other pump-assisted wells.

Defined as the backflow of a liquid film into a wellbore, liquid loading is a severe issue for gas wells because it decreases the production rate of gas. If the rate of liquid accumulation in the wellbore is extremely high, the production rate will significantly decrease, and, under extreme cases of accumulation, the operating company will abandon the well, leading to substantial financial losses. Consequently, to avoid this, it is appropriate for the operating company to predict and identify the liquid loading status of the gas wells and use practical tools and pathways to prevent such a loading. This paper introduces a model based on a liquid film reversal to predict liquid loading. It adopts the momentum balance equation of each phase as a basis and transcends the limits of earlier models. The proposed model relies on the theory, which assumes that the loading phenomenon initiates when the transition from an annular flow (liquid film surrounding the gas core) into a slug or churn flow takes place. Furthermore, the developed model considers the influences of the deviation angle, the tubing diameter, and the void fraction. The efficiency of the proposed model is evaluated by comparing it with few renowned existing models using vertical, inclined, and near-horizontal published gas field datasets, newly acquired ones, as well as laboratory datasets from published papers. As a result, the proposed model provides both the highest prediction accuracy and the least average errors. Further results show that the tubing diameter and the inclination angle are the leading influential parameters of the critical gas flow velocity/rate. Consequently, as the proposed model outperforms the earlier published models, it is the most suitable model for identifying and predicting the liquid loading in vertical, inclined, and near-horizontal gas wells.

Electric Submersible Pump (ESP) is currently widely employed to help enhance production for nonlinear-flowing well with high production and high water cut well. However, ESP broken shaft is common in the oil industry. The broken shaft leads to production disruptions, resulting in significant economic losses. The objective of this paper is to evaluate Principal Component Analysis (PCA) as an unsupervised machine learning technique to detect the cause of the breakage of the ESP shaft. This method was successfully applied in the Penglai block of Bohai Oilfield in China to detect the ESP shaft fracture in real-time. A two-dimensional plot of scores of Principal Component 1 and Principal Component 2 can be used to identify different clusters of the stable region, unstable region and failure region. By this means, potential ESP shaft fracture will be found when the cluster starts deviating away from the stable region. Moreover, a PCA diagnostic model is built to predict the time at which the ESP shaft fracture occurs and to determine the main decision variable most responsible for ESP broken shaft. This paper demonstrates that the application of the PCA method performs well in monitoring the ESP operation system and predicts the impending breakage of ESP shaft with high accuracy.

Vortex tool is a new technique for the liquid unloading in gas wells. But it lacks a mathematical model to describe and predict the effect of vortex tools. In the present work, according to the axial, radial and circumferential momentum balance of the gas phase and liquid phase, the governing equations of vortex flow model have been established. Then thickness of liquid film and gas and liquid vortex flow intensity as well as the pressure drop gradient can be calculated. The calculation results and the previous experiments indicate that the pressure drop of the gas–liquid flow can be reduced by 5% ~ 25% with the vortex tool, and the vortex flow model has an average relative difference of 6.01%. The model results show that there are two mechanisms for reducing the pressure drop under the vortex flow condition. In addition, the research results show that vortex tools with bigger helical angle will lead to higher vortex flow intensity. The decay rate of vortex flow intensity decreases along the pipe as liquid velocity increases and the vortex flow working distance can be calculated by the vortex intensity gradient and initial vortex flow intensity.

Buckley–Leverett displacement equations have been derived strictly from linear flow systems, and have been verified by linear flow experiments only. This paper presents analytical algorithms to calculate recovery factors for radial flow systems, which is expected to be more accurate for peripheral water-flooding reservoirs. The proposed equations have been verified with field data. The original Buckley–Leverett equation generally results in much lower recovery factors that barely match the well cumulative production at interest. Consequently, the estimated ultimate recovery (EUR) by volumetric methods tends to be low. As a result, the production projection according to volumetric EUR is not reasonable in comparing to the historical performance. The proposed analytical model improves the prediction of reservoir performance.

Coalbed Methane (CBM) has become an important gas resource in the last several decades. The brittle property of coal matrix and overflushing operation make the migration of coal fines inevitable. As the liquid flows below a critical velocity, the coal-fines accumulate in the bottomhole. This leads to a significant production decline causes the problems of pump failure/underperformance, severe liquid/solid loading etc. It is important to study the apparent transport mechanisms of coal fines in the wellbore, which is crucial in terms of optimization design, avoiding coal fines setting and burying pump in some extreme cases. By innovative experiment under flowing conditions, this paper presents a piece-wise regressed correlation to calculate the critical velocity to lift the coal fines at different sizes, and consequently identify the onset of coal fine loadings in wells. Operators can then maintain the de-watering rate above the calculated critical velocity, which indeed lowers the maintenance frequency and related operational costs. The origin of mobile coal fines and/or particles falls into categories: 1) large coal fines created during drilling and completion, 2) and small coal fine generated in production and migrate through cleats, cracks, and fractures into bottomhole. The former is large in particle size but has a small volume in total. The latter is small in particle size while has a large cumulative volume. Because large particles required a high liquid velocity to be removed to the surface and are major cause of equipment failure. Small coal fines, although are the majority of migrating coal during back-flow after completion and during production, are easier to be lifted to surface and require a low lifting velocity. The velocity that can remove large coal fines will not have difficulty to lift small coal fines and will prevent them accumulating at bottomehole. Therefore, we focus on the removal of large solids because it is more important. The purposes of this study are to estimate statics settling velocity and critical velocity, which are critical to the selection of appropriate operation parameters.

Summary This paper presents innovative iteration algorithms for multi-interface heat transfer in pipe flow. To the best of our knowledge,this is the first approach derived from the drift-flux model (DFM), which is more competent than mechanistic models for high-slippage gas/liquid flow. The mass- and momentum-conservation equations are inherited from literature and we have written them in the differential forms. In parallel, we thoroughly analyzed the heat-flux conservation among different layers and successfully presented the derivatives of temperature in location and time. Finally, the solution is obtained numerically to capture the temperature/ pressure-distribution profiles under transient conditions. For waxy-crude fields, it is critical to sustain the flowing temperature above the wax-appearance temperature. This is especially challenging for gas-lift-assisted wells. The injected gas, commonly at a relatively low temperature, makes this flow-assurance problem sophisticated. An effective practice is to heat up the flowing fluid by installing an electrical cable in tubing. The heat exchange happens at three interfaces in the production system: between cable and flowing crude, flowing crude and injected gas, and injected gas and formation. It is challenging to model such a multiphase production system, including an inner annulus inside the tubing, because once the electrical cable is installed, an outer annulus is where the gas is injected. To optimize this production system, a rigorous transient multiphase and multi-interface heat transfer simulator is required. By integrating the subsurface boundary condition explicitly, new algorithms can optimize the cable length, heating period, supplied power, or gas-injection rate for the aforementioned production system. This new method has been applied successfully for several gas-lift-assisted wells in a waxy-crude field located in northern China. The power consumption has decreased noticeably by 30% more than the historical field performance. The delegated optimization scheme reduces the shut-in time in winters, which promises cost-savings. The presented model not only satisfies the exceptional modelling requirements for periodically heating crude producers, but it also is appropriate for other heat-transfer investigations under transient multi-interface and multiphase-flow conditions.

Pipeline blockage, which results from solid and hydrocarbon deposition caused by changes in pressure, temperature, or composition, is a critical issue in oil and gas production and transportation systems. Sometimes blockage, which extends several miles in the long-distance pipe, can be approximated as a pipe with a smaller diameter. While the earlier work focused on treating pipeline blockage as a choke for its limited size and length, this study attempts to analyze the relationship between the pressure distribution and the blockage size/length when analyzing the blockage characteristics under different situations. This paper explores the distribution of pressure and pressure gradient around the pipeline blockage under different operating conditions. Three-dimension (3D) computational fluid dynamic (CFD) simulations under steady-state are carried out to examine the effects of blockage diameter, blockage length, and blockage location. The relationship between the pressure drop and blockage characterization is predicted. A forecasting model for blockage sensing and localization is proposed. Lab experiments are conducted to compare the simulation results to measured data and the accuracy of forecasting model is evaluated. The study indicates that CFD simulation results match the experiment data and the model is a useful tool in detection of pipeline blockage.

Petroleum exploration and production from shale formation have gained great momentum throughout the world in the recent decades. Producing hydrocarbons from shale is challenging because of the low porosity and permeability. It is imperative to investigate permeability of the shale formations to better understand the well. Permeability is also one of key parameters in modeling fluids flow in matrix in reservoir simulation. Due to the nature of tight formation, the measurement of shale permeability is time-consuming and cost expensive. These prohibit performing the permeability measurement for a volume of samples. This paper proposes a new method to reduce the measurement-time tremendously thus leading to low-cost and effective core analysis. The new method is more objective than oscillating pulse method, whose permeability is highly uncertain under the condition of low signal-to-noise ratio and is subject to individual interpretation. The developed method evaluates the permeability under unsteady-state flow thus requires short period to determine flow capacity of low permeability rock. It reduces the measurement-time and experimental cost significantly. This new investigation is differentiated from the traditional methods such as Gas Research Institute (GRI), oscillating pulse, or pulse decay methods. Our method can overcome the disadvantages of other methods thus it indeed becomes an important supplement for industry. Further, this method has been rigorously developed from theoretical base, thus it is reliable and accurate for core analysis. The reproducibility of the proposed method is higher than oscillating pulse and pulse-decay methods.

To make completion selection mathematically, a comprehensive well completion system evaluation system was established including 3-class, 14-indicator including technical, managerial, economic, and risk indicators. Mutation theory was first introduced to determine the weights. Combined with fuzzy mathematics, the fuzzy membership function mutation was developed to act as the evaluation way. After 3-class judgment, the completion method with the maximum value of membership function was preferred. The method was applied to the East China region and targeted in 10 directional and 2 horizontal wells. Results showed that the comprehensive model is of high accuracy.

In the past few decades, Coal-Bed Methane (CBM) has become an important source of energy especially in North America. The methane adsorbed within the coal is in a near-liquid state. The open fractures in the cleats are commonly saturated with water. To develop CBM reservoir, water in the fracture and coal seam must be continuously pumped off from coal seam to reduce pressure and desorb gas from matrix. Although operators desire to produce hydrocarbon quickly, a too fast dewatering rate can irreversibly damage matrix desorption process, which can lead to an unfavorable ultimate recovery. Further, the aggressive production rate can potentially release the coal fines and drive them into pump, which increases maintenance effort and cost. Even worse, the de-watering process fluctuates because of the rock porosity and permeability changes resulting from the brittle coal seam and pressure reduction. Therefore, it is critical to adjust the pump operating parameters in a timely manner to maintain a continuous/intermittent production. Ten CBM wells are located in a remote area, which makes the access to wellsites difficult. Previously engineers had to evaluate well performance and optimize the pump on-site, which is limited by a monthly basis. We firstly developed an automatic data processing system using the advanced Echosounders, which can measure the water level in real time. The reservoir pressure can be then monitored dynamically through interpreting the detected water level. With an automatic-wireless data transferring system installed on-site and a closed-loop control program to receive, process, and interpret data, the pump operating parameters can be changed in real time through remote control. This system not only identifies the downhole problems in real time, but also reduces the pump maintenance frequency from 40 days to 75 days statistically and numbers of trip to well site. Further, the gas production rate has been averagely improved by 30% for the 10 wells. The authors firstly developed an automation data processing and control system in the favor of advanced echosounders. Based on the interpreted reservoir pressure, we can avoid aggressive production by adjusting the pump operating parameters in real time, which eventually results in a better ultimate recovery. The developed workflow (automatic echosounder data acquisition, real filed data transferred to central office, data processing, interpretation, and simulation in computational system, adjustment commands to operating system) is especially valuable for the locations difficult to access.