bluuebunny/crossref_metadata_2025 huggingface dataset:
Determining Viscoelastic Models from Seismic Attenuation Measurements
Authors: Liu Xu , Greenhalgh Stewart
Published: April 2019

We have developed two simple deterministic methods to extract the parameters of viscoelastic models from seismic data. One is for the Zener model using phase velocity dispersion observations and the other is for the single fractional Zener model (Cole-Cole model) using attenuation versus frequency observations. The observations here represent either the arbitrary frequency-dependent dispersion behaviour from actual measurements or from some physical dissipation mechanism(s). In this contribution, it is also proved that similar to Zener model, the attenuation factor curve for the Cole-Cole model, on a logarithmic frequency-axis, symmetric about the frequency corresponding to the peak attenuation value, the peak frequency itself is equals to the inverse square root of the product of the two (stress and strain) relaxation times.

The Cole-Cole model has a broad dispersion response over an appreciable frequency range, but is not very suitable for replicating complicated seismic attenuation dispersion curves which exhibit multiple peaks. In this case, we use the General Zener (GZ) model comprising multiple Zener elements and the General Fractional Zener (GFZ) model comprising multiple Cole-Cole elements to approximate the attenuation observations. Their parameters, including relaxation times and fractional derivative orders, are determined using a simulated annealing inversion method. Instead of searching for the relaxation times directly, we search for the Zener peak attenuation points (attenuation value and corresponding frequency, each of which corresponds to a pair of relaxation times. There are distinct advantages of such an approach.
Characterization of Continental Shale Gas with Integrated Geoscience-Engineering Approach
Authors: Zhang Lixia , Ma Fujian , Jiang Chengfu , Xian Chenggang , Liu Chao , Zhao Xianran , Gao Yagang , Wang Qing , Guo Chao , Pan Yuanwei
Published: April 2019

Marine shale gas plays have been well developed worldwide; however, continental shale plays have been untapped until recently. Globally, there are no or few successes for continental shale gas development, although marine shale gas has been commercially exploited worldwide for decades. Ordos Basin, China is a rich continental shale gas play in Mesozoic and Paleozoic target zones. The proven resource is about 1600×108m3 (5.6 Tcf). The first geoengineering project for continental shale gas globally was conducted in this play in China.

The paper presents a case study that illustrates the challenges of a lacustrine shale gas well from integrated study to fracturing and well testing. Although an integrated geoscience-engineering workflow is used in the study, only results from drilling and logging are presented in the paper. Discussions and recommendations for future exploitation are presented.

The deep or semi-deep lacustrine deposits in the Triassic Yanchang formation, Ordos basin is the interval of interest in the study. The study area is in the southeastern part of Ordos basin, China, and the area is characterized by a single westerly dipping monocline with undeveloped faults . The interpretation of the seismic data showed no obvious faults. However, natural fractures were interpreted with ant tracking analysis, and these may influence reservoir and completion quality.
Numerical Study on Proppant Transport and Placement in Complex Fractures System of Shale Formation Using Eulerian Multiphase Model Approach
Authors: Yang Ruoyu , Guo Jianchun , Zhang Tao , Zhang Xudong , Ma Jian , Li Yang
Published: April 2019

Slick-water fracturing treatment is one of the most effective method to develop shale reservoir, which creates complex fracture system by connecting the pre-existing natural fractures. However, the proppant transport and placement behavior is quite different from that in conventional bi-wing fractures due to the low viscosity fluid system and intersections between fractures. The goal of this work is to simulate and understand the characteristic of proppant transport behavior in Complex Fractures network.

A Eulerian multiphase model is introduced to simulate the transport and settling behavior in the hydraulic fracture network, which takes turbulence effects and friction stress between the proppant particles into consideration and fully couple the fluid phase with particle phase. Simulation work was conducted to investigate the control mechanism and influencing factors for proppant transportation from main fracture into secondary and tertiary fractures.

The simulation results indicate that a small proppant dune quickly forms in the main fractures first, and almost no proppant enters the lower grade fracture until the proppant dune in the intersection reaches a specific height. With continuous injection of slurry fluid, majority of the proppant enters in the lower grade fracture which is controlled by gravity rolling from the dune in main fractures and fluid drag force, and the proppant settles quickly and gradually reach their own equilibrium height. Parametric study shows that smaller proppant density and particle size can also help proppant transport into secondary fractures and form a higher equilibrium height dune, resulting in larger effective propped area. Moreover, when the lower grade fracture is closer to the inlet entrance, the proppant is more likely to transport in, and the height of sand dunes formed in the fractures is higher.

The proppant transport process in complex fracture systems is simulated by Eulerian Multiphase Model in this paper. This study extends the understanding of the process and mechanism of proppant transport in complex fracture system and controlling factors, which helps optimize hydraulic fracturing design in shale formation.
Use of Data Analytics to Incorporate Geophysical Surface Uncertainty into Subsurface Modelling
Authors: Hardy Madeline , Lockwood Andrew , Thomas Peter
Published: April 2019

Uncertainty is present at every stage of the subsurface modelling workflow and understanding it is an ongoing challenge for the petroleum industry. Quantifying this uncertainty is a rapidly growing field of study as increasingly available high-performance computing enables the application of traditional statistical methods to this problem. However, the extension of these methods to spatial data remains a challenge for which there is no immediate solution. This paper describes the use of data analytics techniques to incorporate spatial uncertainty in reservoir surfaces into subsurface modelling. A metric usually applied in image analytics, the Modified Hausdorff Distance, is adapted for this purpose. The workflow involves sampling the domain of possible surface realisations, characterising them using this metric and determining the most efficient subset to represent the entire data set. The value of this process is that the selected subset captures spatial uncertainty in the surface rather than only gross rock volume. The proposed technique proved to be a simple process that was able to easily select these surfaces from a stochastically generated set and has been successfully applied to the top reservoir surfaces in two fields.
Accumulation Stages Division of Carbonate Hydrocarbon Pool in the Western Yingxiongling Area of Qaidam Basin
Authors: Wu Kunyu , Zhang Yongshu , Zhang Shenqin
Published: April 2019

The Qaidam Basin is a big intermountain Mesozoic-Cenozoic petroliferous basin in western China. The huge thickness Cenozoic strata and tectonic deformation formed a good combination of hydrocarbon sources, reservoirs and caps, leading to huge hydrocarbon potential of the basin. The Western Yingxiongling Area locates in the western part of the Qaidam basin, during the Cenozoic era a special tectonic dynamics background was formed by the joint control of the sinistral strike-slip fault of the East Kunlun and the sinistral strike-slip fault of the Altun (Fu et al., 2016). The tectonic deformation in this area is very strong, which makes the distribution of hydrocarbon pools extremely complicated. The breakthrough of wells Shi 20 and Shi 24 in the Western Yingxiongling Area in the 1980s confirmed that there are high oil and gas enrichment zones in this region. However, the distribution characteristics of oil and gas reservoirs in this area are not ascertained due to the lack of technical means and theoretical understandings. In recent years, based on the results of three-dimensional seismic exploration, studies on sedimentology and reservoir, and hydrocarbon geochemical evaluation, the geological characteristics of deep reservoirs in this area were systematically recognized. The structure of this area is characterized by "double layer", with large trap area and diverse types. At the same time, the region is in the favorable source depression area of the basin with sufficient hydrocarbon sources (Jin et al., 2001). The latest reservoir research discovered the commonly developed dolomite intergranular pores and the dissolution pores, which changed the former understanding of single fractured reservoir (Li and Wang, 2001). Since 2015, the exploration of the Western Yingxiongling Area has made remarkable progress on the basis of new theoretical understandings and technical application, and has successfully drilled a batch of high-yield wells such as Shi 38, Shi 205 and Shi 1-3 et al. In order to gain better understandings on the hydrocarbon pool in the Western Yingxiongling area, performing a systemic analysis on hydrocarbon pool stage division is necessary.
Weight-on-Bit Self-Adjusting Dual-Diameter Bit Leads a Step Change in Drilling Bit Technology
Authors: Hu Huaigang , Guan Zhichuan , Wang Bin , Liang Deyang , Sun Meiwei , Wang Xiaohui , Chen Weiqing
Published: April 2019

With the deepening of the large-size well section, mitigating drilling vibrations and pushing the upper limit of performance while drilling in a single bit run remains a challenge for PDC bits, and the problem of slow rate of penetration (ROP) has seriously affected the drilling cycle and cost of the whole well. Recently, new Weight-on-Bit(WOB) Self-Adjusting Dual-Diameter Bit (WSDB) technology was introduced to help overcome these challenges.

The structure of the bit is designed, the stress state of the stepped bottom hole is analyzed by using the general finite element software. The results of theories are corroborated with testing in the laboratory, which also demonstrates the ability of the technology to reduce drilling vibrations and push the performance envelope. The bit is mainly composed of four parts, the pilot section, the reaming section, the WOB regulating spring, and the transmission assembly. The technology provides the bit with the ability to continuously adjust its depth of cut control(DOCC) characteristics to suit the drilling environment and to mitigate of stick/slip vibrations. Because of the presence of the pilot section, the stress concentration area on the shoulder of the reaming bit is obviously reduced, and the stress unloading area in the junction of the reaming bit and the pilot bit is larger, therefore the rock breaking mechanical specific energy is reduced greatly in stress releasing area, thus the rock breaking efficiency is improved. Through the indoor comparison test, it is found that compared with the conventional PDC bit, the ROP of WSDB can be increased by up to 325% when drilling in limestone, which also indicates that Bit B has the characteristics of faster and more efficient drilling with low TOB.

A method to make full use of bottom hole stress releasing effect and reduce rock compressive strength to improve the rock-breaking efficiency is put forward, and a matched WSDB is developed. The mechanical specific energy required in the rock-drilling process can be greatly reduced, at the same time DOC characteristics of the bit are dynamically adjusted, which could remit the stick-slip vibration caused by a rapid change of DOC, thus the rock-breaking efficiency is improved.
Development of an Erosion Dynamics Model and its Application to Wells and Facilities
Authors: Wang Jason , Sami Muhammad , Troshko Andrey , Gallo Federico , Mayer Christian , Tenny Matthew
Published: April 2019

When producing hydrocarbons from an oil well, managing erosion of both surface and subsurface components caused by solids in the flow stream is critical to maintaining operations integrity in both land and offshore assets. Although component lifetime prediction has advanced in the past few decades, the prediction's accuracy remains a major oil and gas industry challenge. Current computational models only provide an initial erosion rate which is usually assumed constant until equipment failure. However, observed erosional rates vary as a function of time due to the geometrical changes caused by equipment material loss, which result in variations in solid particle impingement velocity [1] thereby either accelerating or slowing the erosional process. The constant rate simplified erosion model often produces inaccurate results that can lead to unexpected equipment failures or unnecessary equipment upgrades depending on whether the rate accelerates or decelerates. Therefore, developing a transient erosion model to capture the variations of erosional rate is needed for an accurate prediction of equipment lifetime.

This paper presents an implementation of an erosion dynamics model in ANSYS FLUENT, a commercial computational fluid dynamics (CFD) software, to capture the progression of transient erosion. The model has the capability to capture the effects of surfaces receding from erosion at each time interval. By dynamically adjusting these surfaces and recalculating the local flow conditions in the area, this method can predict new erosion rates for each time interval and achieve fully coupled geometry-flow-erosion interactions.

This new erosion dynamics model was validated against experimental data from both literature and physical testing, and was determined to have accurately captured the observed erosion trends over time in terms of location and magnitude. The model was then employed to study two real world applications: 1) in evaluating the erosion risk for a high-rate water injector, it predicted the evolution of damage to a coupler designed to connect different diameter pipes, and 2) in analyzing facility piping systems connected to an unconventional well, it predicted the transient erosion trend from proppant flowback, which allowed for pipe geometry optimization to increase in erosional life expectancy.
Efficient Flow Rate Profiling for Multiphase Flow in Horizontal Wells Using Downhole Temperature Measurement
Authors: Zhang Shuang , Zhu Ding
Published: April 2019

The downhole temperature measurements have become a powerful tool for fracture diagnosis. Multiphase flow is common in fractured horizontal wells, and its effects on temperature behavior are noteworthy. To interpret downhole temperature measurement quantitatively, we need an integrated flow and thermal model to handle multiphase flow with reasonable computational efficiency while maintaining maximum accuracy that can be achieved. This study presents the multiphase black-oil thermal and flow model and shows its applications on temperature interpretation.

The integrated multiphase black-oil thermal and flow model can simulate the transient temperature behavior during the injection of the hydraulic fracturing, shut-in, and the production. The model simulates reservoir flow (pressure and velocity) and thermal (temperature) for a multi-stage hydraulic fractured horizontal well. Previously developed wellbore model for two-phase flow is adopted in this study. The reservoir model solves the mass balance, Darcy's law and energy balance in three dimensions. We assume that the oil and water components are immiscible, and the gas component is only soluble in oil but not in water. The reservoir model and wellbore model are coupled interactively through boundary conditions to each other.

The multiphase black-oil thermal/flow model is validated against the compositional model. The results show the consistency between these two models, and the multiphase black-oil thermal/flow model significantly reduces the computational time. This study gives guidance on when and how to apply this black-oil thermal model to fulfill its full advantages. This work proposes a modified inversion workflow particularly for liquid production based on the previous study and presents a field example of implementing this developed thermal model to interpret temperature data to flow rate profile for a multistage fractured horizontal well with the multiphase flow. The results reveal this multiphase black-oil thermal model is efficient and can be used to interpret temperature measurements for multiphase flow quantitatively with reasonable assumptions.
The Study of Surfactant Huff and Puff of Horizontal Well with SRV in Tight Oil Reservoirs
Authors: Weirong Li , Zhenzhen Dong , Gang Lei , Cai Wang , Huijie Wang
Published: April 2019

A local refined model, using micro-seismic data to model fracture geometry, is presented to study huff-n-puff surfactant injection in a tight oil reservoir. The goal of this study is to understand the key parameters that control the surfactant huff-n-puff performance in tight oil reservoirs.

In this new approach, natural fractures in tight oil reservoir is described by dual permeability model, and stimulated reservoir volume (SRV) based on micro-seismic datais is modeled by local refined grid. In the study, sensitivity analysis is carried out to optimize oil recovery, such as wettability change, interfacial tension, surfactant adsorption, huff-n-puff cycle, etc.

The results indicate that surfactant injection is a favorable method to mobilize oil in tight oil reservoirs; wettability alteration and interfacial tension of surfactant are the dominant mechanisms for the oil recovery through surfactant injection; surfactant adsorption is a key element to the success of the wettability alteration process; and soaking time does not have obvious impact on recovery. The incremental oil recovery factor over primary production for 15 years of total production is up to 3.5% of OOIP that doubles the recovery from the primary production.

The study gives new method to study surfactant injection in the tight oil reservoirs when micro-seismic data available. It can be helpful for modeling other EOR process in tight oil reservoirs. The results also can guide surfactant injection in field development for similar tight oil field.
Accurate Original Resistivity Inversion in a Heterogeneous Thick Flooded Reservoir Through Electrical Interpretation Unit Classification
Authors: Liu Huan , Xu Jinxiu , Cui Yunjiang , Lv Zuobin , Shi Xinlei
Published: April 2019

Low resistivity is a main feature of flooded reservoir in injection fields. The key to evaluate flooding severity is to reconstruct resistivity in its' original condition. In this process, the routine method is to find a relationship between resistivity and other logs to rebuild unflooded resistivity. However, it is very sensitive to formation parameters and prone to have larger error due to ignoring the difference of lithology, reservoir and electrical properties driven by geological background.

This paper proposes a method to classify reservoir into different electrical interpretation units to address the problem that routine methods have. Firstly, reservoir was divided into different logging facies through multi-resolution graph-based clustering(MRGC). Secondly, a database of the relationship between logging facies and lithology in aimed reservoir was built based on the core, petrophysical logging data and so on. Eventually, electrical interpretation units were obtained based on the database and reservoir resistivity. Resistivity models of origin field were built for each electrical interpretation unit, which could improve the accuracy of original resistivity calculation dramatically.

In the studied field, five logging facies were defined in a coring well using MRGC method. The relationship between each logging facie and its lithology were constructed as well. Each logging facie can be recognized though cross-plots from conventional logs. Meanwhile, considering reservoir fluid properties, through finding similar electrical properties in the reservoir with same logging facies and lithology, the studied well could be further divided into three interpretation units. With similar lithology and reservoir properties, reservoir heterogeneity from the same electrical interpretation unit decreases, plus bearing similar electrical property, the influence from saturation difference of the original field has weakened. Through the previous illustrated model, it has demonstrated a good effect in evaluating the original resistivity in thick layers of the M field from Bohai Bay. Comparing with the result from routine method, the resistivity from the proposed method has a better match with the resistivity from unflooded area, consequently, increase the evaluation accuracy dramatically.

Eventually, the classification of logging facies and electrical interpretation units from key wells can be spread to flooded wells to calculate the unflooded resistivity, as a result, a more accurate flooding severity evaluation could be obtained. It could provide more reliable data for further residential oil development.
3D Permeability Characterization Based on Pore Structure Analysis and Multi-Parameters Seismic Inversion and Its Application in H Oilfield
Authors: Chen Xin , Wang Guihai , Wang Zhaofeng , Liu Zundou , Liu Zhaowei , Cui Yi , Tian Wenyuan , Wei Xiaodong , Hou Liugen , Yang Ke , Chen Gang , Xia Yaliang , Yan Xiaohuan , Zhang Zeren , Liu Jingluan
Published: April 2019

To improve the accuracy of permeability prediction, seismic constraint and sedimentary facies has often been adopted in conventional methods. However, it is porosity that both of them constrain, rather than permeability, and different pore structure with different permeability, the accuracy of permeability prediction cannot be radically improved. To address the problem of permeability prediction in carbonate reservoir, new permeability prediction technique workflow were summarized based on pore structure analysis and multi-parameters seismic inversion: division reservoir types based on the pore structure, construction of the rock types identification curve, carry out a rock type inversion and a porosity inversion constrained by seismic impedance respectively, and then get a final permeability prediction volume according to the porosity-permeability relationship and pore structure of core samples. It breaks the bottleneck that is difficult for seismic impedance (continuous variable) to constrain rock type (discrete variable), then constrains pore structure (continuous variable) related to rock type instead, and converts it into rock type using multi-parameters seismic inversion. According to the certification of new wells, this workflow have been applied successfully in carbonate reservoir of H oilfield in Middle East, it not only improves the prediction of rock type in space, but also permeability prediction accuracy.
The Rock Mechanical Properties of Lacustrine Shales from Ordos Basin
Authors: Yu Hongyan , Li Xiaolong , Wang Zhenliang , Rezaee Reza , Gan Litao
Published: April 2019

Abundant shale oil and gas resources have been discovered in the Zhangjiatan shale of the Yanchang formation in ordos basin in recent years. Zhangjiatan shale is a typical lacustrine shale, which is different from Marine shale in physical properties. Most previous research has focused on Marine shale. In order to understand the rock mechanical properties of Zhangjiatan shale, we conducted dynamic and static elastic properties experiments. We selected argillaceous shale and silty laminae shale in Zhangjiatan shale as samples. In order to obtain the static Young's modulus and Poisson's ratio, we use the triaxial pressure test. We use the dipole log to measure the acoustic velocity down the hole, and then we calculate the dynamic Young's modulus and Poisson's ratio of the sample based on acoustic velocity. Young's modulus of argillaceous shale is slightly smaller than that of silty laminae shale and the Poisson's ratio of argillaceous shale is also smaller than that of silty laminae shale. The brittleness of argillaceous shale are greater than that of silty laminae shale, as a result, argillaceous shale is much easier fracturing under pressure. We plotted the cross-plot of RCS, elastic properties and TOC and reached a conclusion that the mass ratio of clay to quartz and feldspar determined the brittleness and deformability of rock, while organic matters also affected the elastic properties of rock. Therefore, the elastic properties of shale are not controlled by a single factor, instead of multiple factors.
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

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

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

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 >20×104m3 /d is poor, and the SPT of wells with AOF <20×104m3 /d is long; the latter wells with AOF > 4×104m3 /d has poor stable production capacity, while well with AOF <20×104m3 /d has a long SPT. The higher the productivity index, the shorter SPT, the shorter SPT for wells with gas production rate> 3 %, and the longer SPT for wells with gas production rate< 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 (< 0.1 MD) require a large pressure differential to reach a certain gas production. High permeability reservoir (> 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 >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

ASP 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

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

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

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

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.