bluuebunny/crossref_metadata_2025_split huggingface dataset:
A Transient Plunger Lift Model for Liquid Unloading from Gas Wells
Authors: Zhu Jianjun , Zhu Haiwen , Zhao Qingqi , Fu Weiqi , Shi Yi , Zhang Hong-Quan 
Published: April 2019

Accompanied with liquid condensation, natural gas production wells suffer from liquid loading if the gas flow rate is insufficient to carry liquids to the surface. With continuous production, the reservoir pressure decreases due to reservoir depletion, resulting in decrease of gas flow rate and inability to carry liquid upward. Then, the produced liquid accumulates in the well bottom and creates a static liquid column, adding a backpressure against reservoir pressure and reducing gas flow rates until the well production ceases. Due to many advantages, such as low operation cost and prevention of paraffin deposition along wellbore, plunger lift has been widely used in gas wells for the removal of liquid column and rescuing dying gas wells from liquid loading.
The existing plunger lift models in literature are imperfect due to either limited field applications or oversimplified assumptions, which lead to considerable prediction errors. Starting from Gasbarri and Wiggins (2001) dynamic plunger lift model, several components in the cyclic movement of a plunger can be identified with each comprising a set of specific governing equations, namely, plunger upstroke, gas blowout, plunger fall-down, pressure buildup etc. Considering the gas flows with plunger moving in the tubing, the new model accounts for the instant velocities during plunger rising and falling. Reservoir performance as a component is included in all stages of plunger lift processes. By solving the transient governing equation in each component of plunger lift iteratively, the new model outputs the plunger velocity/acceleration, pressure versus time, production rate versus time etc. Compared to previous plunger lift models, improvements have been made on the equations of plunger rising and falling velocities. The present model also accounts for different reservoir performances. Oil and water cases from previous studies are used to evaluate the present model which provides more accurate and reasonable predictions of plunger rising and falling velocities.
Exploration and Practice of Methane-Leading Reservoir Stimulation Technology of High-Rank Coalbed Methane
Authors: Zhu Qingzhong , Yang Yanhui , Chen Longwei , Wang Yuting , Chen Biwu , Liu Chunli , Zhang Chen , Wang Xiaoxuan 
Published: April 2019

Abstract
In order to solve the problems of poor adaptability of reservoir stimulation technology and low gas production of single well in high-rank coalbed methane (CBM) reservoir, a new concept of "methane-leading" reservoir stimulation technology and the corresponding technology method system are put forward. The concept of "methane-leading" reservoir stimulation technology emphasizes the complexity of the coal reservoir and the energy releasing process in the coalbed methane development. Through targeted artificial stimulation, a multi-stage interconnected fracture network system is built to reduce seepage resistance and finally improve the gas production of single well. The characteristics of coal reservoir and problems of traditional stimulation technology are analyzed in this paper. And the "methane-leading" reservoir stimulation technology focus on the optimization of the "sweet section", the release of injected energy and the expansion of area stimulated by the fracture network. The application results in the CBM field in the south of Qinshui basin, Shanxi Province, China, shows that the gas production of a single vertical well is more than twice that of an old well in the same area, reaching 2500~3000 m3/d and the average gas production per horizontal well is over 10000 m3/d, indicating a good application prospect. The innovation of this paper lies in that a new concept of "methane-leading" reservoir stimulation technology and the corresponding technology method with CBM characteristics are put forward. It provides new ideas and methods for effectively improving the gas production capacity of CBM single well, realizing efficient development of high-rank CBM and promoting the healthy development of CBM industry.
Unravel the Lacustrine Shale Oil Reservoir Potential in China by Integrating Advanced Logging Technologies and Special Core Measurements
Authors: Liu Guoqiang , Hou Yuting , He Junling , Zhang Hao , Wu Jinlong , Zhao Xianran , Li Huayang , Wu Fangfang , Li Shenzhuan , Wang Yuxi 
Published: April 2019

Abstract
Most shale oil resources in China are lacustrine deposit. The reservoirs are usually characterized by complex lithology and high heterogeneity with various mineral compositions (quartz, carbonates, feldspars, pyrites and volcanic ash), total organic carbon and pore structure. How to delineate the shale oil reservoir, how to identify the ‘sweet spots’ and its distribution are the two major challenges and objectives for this study.
To answer the question, a systematic workflow was proposed by integrating the advanced logging technologies (such as nuclear magnetic resonance, micro-resistivity imager, spectroscopy data, array dielectric tool) with special core measurement data. Firstly, the shale oil reservoir was classified into different types according to the logging responses. Secondly, core samples were chosen from each type and sent out to lab for a series of core special experiments to test the microscopic properties. Finally, the advanced core analysis results and logging technologies were integrated to depict the characters of the different types of shale oil reservoirs from microscopic to macroscopic scale. And by comparing with testing data, the features of best shale oil reservoir type can be identified, and the distribution and potential of shale oil reservoir can be unraveled.
The new approach helped to get a thorough understanding of the shale oil reservoirs characteristics, such as lithology, mineral composition, pore types, pore size distribution, oil content, kerogen type and maturity of organic matter, organic carbon content and distribution. Six different kinds of shale oil reservoir facies were classfied from loging responses, inculding super high gamma ray siliceous shale, high gamma ray siliceous shale, high gamma ray argillaceous shale, high gamma ray tuffaceous shale, medium gamma ray siliceous shale and medium gamma ray argillaceous shale. High gamma ray siliceous shale and medium gamma ray siliceous shale are proved to be the best shale oil reserovir, which contains 2~8% of TOC, 2~12% of effective porosity, more than 50% of quartz content and high propotion of macropores.
The method proposed in this project has been implemented in many unconventional reservoirs in china to evaluate the resource potential and get a comprehensive understanding of the shale oil reservoir.
The wells tested based on the recommendation has got promising production after fracturing, which brought client big confidence for future exploration.
Study and Analysis of Engineering Factors for Prolonged Gas Production in Xujiahe Tight Sandstones
Authors: Yao yongjun , Yuan quan , Cai junjun , Zhu jianying , Gan xiaofei , Ruan jifu , Hu guoheng , Zhao xuanzhi 
Published: April 2019

Abstract
The Xujiahe gas reservoir in the central Sichuan is a large tight sandstone gas reservoir with low porosity, low to ultra-low permeability, strong heterogeneity, and poor reservoir connectivity. The estimated reserve is about 200 billion cubic meters of gas. More than 870 wells had been drilled since the discoveries in 1956 and 440 wells are producing. However, nearly all wells produced at financial marginal. The production declined at an unpleasant rate. Water flooding occurred unpredictably due to diverse aquifers. It's been challenging for engineers to establish reasonable production rates and to prolong the stabilized production time(SPT).
In our study, a three-step method was used to scrunize the primary factors affecting the stable production. The first step is to perform a principal component analysis; The second step is to do a cluster analysis; The tlast step is to conduct a comprehensive geological evaluation. 102 wells data was used in the principal component analysis, the cluster analysis and the comprehensive analysis of geological characteristics. The main control factors were found and, at the same time quantified to the relationship between the main control factors and the SPT.
The analysis results show that the parameters such as absolute open flow(AOF), productivity index, gas production rate, dynamic reserves, permeability and water saturation. The main control factor for naturally Fracture wells and Fracture wells is AOF, for pore-type wells is gas production rate. The stable production capacity of the former wells with AOF &gt;20×104m3 /d is poor, and the SPT of wells with AOF &lt;20×104m3 /d is long; the latter wells with AOF &gt; 4×104m3 /d has poor stable production capacity, while well with AOF &lt;20×104m3 /d has a long SPT. The higher the productivity index, the shorter SPT, the shorter SPT for wells with gas production rate&gt; 3 %, and the longer SPT for wells with gas production rate&lt; 3 %. Fracture wells play a positive role in SPT and reserves production, while pore-type wells are difficult to produce reserves. Low permeability tight reservoirs (&lt; 0.1 MD) require a large pressure differential to reach a certain gas production. High permeability reservoir (&gt; 1 MD) has strong gas phase seepage capacity and can achieve higher production under a lower pressure differential. Water saturation has a great influence on gas phase seepage in low permeability tight reservoirs. At the same gas production rate, the SPT and cumulative gas production decrease with increasing water saturation. The larger the water saturation, the larger the remaining reserves. If the WGR &gt;10m3 / 104m3, the SPT is shorter, and if the WGR is less than 3m3 / 104m3, and the SPT is relatively longer.
Chemical Treatment Scenario of Produced Fluid by ASP Flooding Using NaOH, Alkylbenze Sulfonate and HPAM at Daqing Fields
Authors: Wu Di , Liu Wenjie , Cai Xun , Meng Xiangchun , Yang Yuepeng , Lin Sen , Zhang Shaohui , Wang Cong , Zhang Huiping , Li Yinghui , Zhao Fengling , Zhang Xin 
Published: April 2019

AbstractASP flooding using NaOH, alkylbenze sulfonate and HPAM has been put into industrial application at Daqing Fields. While significantly increasing oil recovery, it has also brought in new challenges for the handling of produced fluid such as precipitation of new mineral particles in the aqueous phase, scale deposition, foam, stable reverse emulsion in both produced fluid and produced water, and expanded rag layers in electrostatic treaters. To facilitate handling of the produced fluid and produced water by ASP flooding, numerous chemicals have been developed and applied, such as antifoams, demulsifiers, dual functional demulsifiers and reverse demulsifiers, sulfide scavengers, chelatants, and alkalines. A comprehensive scenario for the application of the above mentioned chemicals has been developed and applied in the handling of ASP flooding produced fluid at Daqing Fields. The scenario consists of continuous injection of dual functional demulsifier and reverse demulsifiers, antifoams at the inlet of production separators or into the produced water heated, recycled back to wellsites and blended into wellhead produced fluid to facilitate its flow to oil gathering stations, continuous injection of chelatant and alkaline into the produced water recycled back to be the wellheads, temporary injection of demulsifier and alkaline into the feed of bath heaters upstream of electrostatic treaters on an as-needed basis, batch injection of sulfide scavenger into the produced water recycled back to the wellheads, as well as batch injection of sulfide scavenger and alkaline into the feed or backwashing water of media filters treating produced water. The chemical treatment scenario has been successfully applied in 4 ASP projects using NaOH, alkylbenze sulfonate and HPAM at Daqing fields, significantly improving the performances of surface production facilities handling ASP flooding produced fluid.
A Risk-Effectiveness Design Method for Flare Height of Natural Gas Pipeline System
Authors: Wu Xia , Li Chang Jun , Jia Wen Long , Mu Jun Chen 
Published: April 2019

Abstract
The objective of this research is to develop a risk-effectiveness design method for flare height of natural gas pipeline system. The advantage of the proposed design method over the traditional methods is the impacts of population density to flare risk are considered and more economic flare height could be obtained under lower risk levels. The conventional design methods obtain the same flare height for both high and low population density area. A risk-effectiveness model is established by combing the risk cost and the flare construction cost. The optimal flare height is the minimum value calculated by the first derivative of the model. An application is given to show the model's usability under different population densities. The flare height of 19.4m, 21.7 m, 24.3m, and 28.6m are obtained by the method for four different regions with the population densities of 5.2×10−5, 1×10−4, 3×10−4 and 7×10−4 person/m3. The increased flare height implies the increase of the risk levels accompanying with the increase of the population density. A comparison with the design results gained by the API RP 521 method is made to prove the effectiveness of the proposed method. Under the condition that the compensation per person is 40 times of the construction fees per meter, the flare heights get by the proposed method are 69.7%, 78.0%, 87.4% and 102.9% of the API design heights with the population densities of 5.2×10−5, 1×10−4, 3×10−4 and 7×10−4 person/m3. The results show that a lower flare height would be obtained by the proposed method with the population densities lower than 7×10−4 person/m3, and a direct construction saving could be gained under this circumstance, which proved the economy of the proposed method. The main novelty lies in the risk-effectiveness model which combines the loss of human injuries and the cost of flare construction to obtain the optimal design results for different regions. Compared with the traditional method, the proposed method can not only reflect the impact of the population density to flare risks, but is also more economical under certain circumstance. This makes it possible to gain more benefits for flare operators under low risk levels.
Full Scale Geomechanics Review Assisting Drilling Risk Mitigation in Wushi Sag, Beibu Gulf, China
Authors: Guo Shusheng , Gao Yongde , Gui Feng , Wang Shanshan , Bordoloi Sanjeev , Ong See Hong , Du Chao , Wang Shiyue 
Published: April 2019

Abstract
The drilling in Wushi Sag of the Beibu Gulf appears to be problematic with frequent pack-off, tight-hole and stuck-pipe events as well as kicks and losses occurring in different wells. It is of great importance to find out the main cause or causes of these problems so that proper methods and techniques can be utilized to mitigate the problems and reduce the drilling non-productive time (NPT).
A series of drilled wells were reviewed to identify the key wells to be used for the geomechanical modelling and to help with understanding the drilling problems. One of the outcomes of the detailed geomechanical analysis was the realization that the stresses and rock behaviors are mainly affected and controlled by the structures. Wushi Sag can be divided into four structural areas: subsag-steep slope in the south, central inverted structure area, north slope and strike-slip faulting belt in the west. As a consequence of the complex structures, the formation depth varies greatly while some formations are absent or incomplete in some wells due to the well-developed high-angled faults.
An outcome of the study was the understanding that formation pressures are different in every structural area and are controlled by structural location and burial depth. The main overpressure generating mechanism was found to be type-II fluid expansion caused by either hydrocarbon generation or thermal effects, which can be well correlated to the oil window threshold in the area. Under-compaction may also play a role in some cases, but the overpressure caused by this mechanism is usually low in magnitude. Rock properties vary across the Sag while wells are hard to correlate with each other in different structural areas. The stress conditions appear to be different in each area although the main stress regime is strike-slip with the strike-slip faulting belt in the west having the highest stress ratio.
Due to the complexity of the pressure distribution, lateral formation changes and different stress conditions, improper mud weights and casing designs were used in some earlier wells, which likely led to the types of drilling problems listed above. Wells with severe instability problems were generally drilled with lower mud weights compared to the wells with lesser problems. Wells with both pack-off/tight holes and fluid losses usually have surface or intermittent casing shoes set too shallow while not preparing for the steep pressure ramp in deeper formations. Based on the problem diagnostics and geomechanical analyses, recommendations were made to help with the drilling of future wells by mitigating drilling-related instability problems. A series of wells were drilled successfully following the recommendations with all the possible risks properly understood and mitigated.
Economic Analysis of Lost Circulation Events to Optimize the Drilling Process in Basra Oil Fields, Iraq
Authors: Alkinani Husam H. , Al-Hameedi Abo Taleb T. , Dunn-Norman Shari , Flori Ralph E. , Alsaba Mortadha T. , Amer Ahmed S. , Al-Bazzaz Waleed H. 
Published: April 2019

Abstract
Lost circulation is a unique challenge unlike other factors contributing to non-productive time (NPT). Due to the variability in the nature and type of lost circulation prone formations; there is no universal solution to this challenge. This publication presents a new approach to guide the decision-making process of which and when to apply a certain treatment as compared to another. If implemented correctly, a significant reduction in NPT related to lost circulation can be expected. Also, the cost of each treatment, as well as the NPT that is associated with the treatment, were examined in this study. Lost circulation events for three formations which are the Dammam, Hartha, and Shuaiba were gathered from over 1000 wells drilled in Basra oil fields, Iraq using various sources and reports; the treatments were classified by scenario –partial, severe, and complete losses – as well as cost, efficiency, and formation types. This paper is developed based on probabilities, expected monetary value (EMV), and decision tree analysis (DTA) to recommend the best-lost circulation strategy for each type of losses.
This paper utilizes probability and economics in the decision-making process. This is the first study that considers a detailed probability and cost to treat the lost circulation problem. Thousands of treatment scenarios for each type of losses are conducted, and the EMVs for all scenarios are calculated. For each type of losses, the lowest EMV treatment strategy- that is practically applicable in the field and makes sense- is selected to be used to treat each type of losses to minimize NPT and cost. If the losses didn't stop after utilizing the proposed treatment strategies, it is recommended to use liner hanger to isolate the losses zone and then continue drilling. A change in well design is also suggested to help to minimize NPT and cost. In addition, a formalized methodology for responding to losses in the Dammam, Hartha, and Shuaiba formations is established and provided as means of assisting drilling personnel to work through the lost circulation problem in a systematic way.
One challenge in drilling wells in Basra oil fields is the inconsistency of approaches to the lost circulation problem. Therefore, the result of this data analysis provides a path forward for the Basra area lost circulation events and suggests probable methods that can be used in similar formations globally. Additionally, the methodology can be adapted to studying other types of formations and drilling challenges have the same geological properties in any major oil field.
The Fundamental Work to the Pre-Frac Evaluation of Deep Shale Reservoir: Evaluating Reservoir Heterogeneity Based on Principal Components Analysis and Artificial Neural Network
Authors: Zhai Wenbao , Li Jun , Xi Yan , Liu Gonghui , Yang Hongwei , Jiang Hailong , Zhou Yingcao 
Published: April 2019

Abstract
Shale reservoir heterogeneity is more and more focused during shale gas development, especially deep shale gas reservoir buried in the depth of over 3,500 m. However, the evaluation methods of heterogeneity are not always available and poor applicability. In this study, a Principle Component Analysis (PCA)-Artificial Neural Network (ANN) model was presented. The evaluation steps of the model were also given. The validation of the model was confirmed by using a deep shale gas well located in Weiyuan area of Sichuan Basin, China. The results of the validation show that the model presented in this study can be in good agreement with the assessed values of heterogeneity obtained from microseimic events. The developed model's effectiveness was tested by comparing the results acquired from ANN without PCA, where the PCA reduces the dimension of input parameters to improve results of PCA-ANN over 80%. Therefore, the PCA-ANN model can help the engineers evaluate the deep shale reservoir heterogeneity, which provides a tool to give preliminary recommendations of the likelihood of improving the effectiveness of hydraulic fracturing. Implementation of the proposed model can serve as a cost-effective and reliable alternative for the deep shale reservoir.
Novel Application of Distributed Temperature Sensing and CT Real-Time Downhole Flow Measurement Tool for Thermochemical Treatments
Authors: Al-Nakhli Ayman , Arifin Mohammed , Ahmed Danish 
Published: April 2019

Sandstone formations can be particularly susceptible to formation damage due to organic deposits, fine migration, filter cake and formation minerals. Stimulation methods for these types of formations have typically employed mud acid due to the ability to readily dissolve both formation minerals and contaminants introduced into the wellbore/formation during drilling or remedial operations. However, hydrofluoric (HF) based fluids are corrosive, fast spending and causes formation damage by side reactions precipitations, thereby limiting the efficiency of matrix stimulation treatment.
A novel heat generating fluid has been developed as an alternative to conventional matrix stimulation for sandstone formation. The method entails triggering an exothermic chemical reaction in-situ to generate heat i.e. ~&gt;400 °F and localized pressure. Generated heat mobilized near wellbore damage; while the pressure provided lifting energy to flowback the well, therefore, improve well injectivity. Exothermic reactants were subsequently injected via coiled tubing and allowed to soak in the treated wells. The resulting temperature and pressure increase were captured in real-time with distributed temperature sensing (DTS) coiled tubing telemetry. DTS profiling helped in understanding the in-situ exothermic reaction and avoiding post treatment production logging costs. The treatment was executed in different phases while injectivity tests were conducted after each step for each phase evaluation.
To prove the stimulation concept using thermochemicals, the treatment was applied in sandstone wells and showed superior results. DTS and downhole flow tool profiling confirmed a homogeneous treatment along the perforated interval of the well. Post treatment results showed improved well injectivity up to 50 times.
Attempts to realize consistent performance of the conventional stimulation treatments with different formulations have either been cost prohibitive or relatively ineffective. The non-acidic and heat generating fluid holds promise as an economic and a technical solution to well enhancement issues in sandstone reservoirs.