bluuebunny/crossref_metadata_2025_split huggingface dataset:
Integrated Real-Time Pressure Monitoring Enabled the Success of Drilling a HTHP Offshore Well: A Casing Study in Ledong Area of Yinggehai Basin, South China Sea
Authors: Gao Yongde , Chen Ming , Du Chao , Wang Shiyue , Sun Dianqiang , Liu Peng , Chen Yanyan 
Published: April 2019

Abstract
Drilling in Ledong field at Yinggehai basin of South China Sea faces challenges of high-temperature and high-pressure (HTHP). The high pore pressure and low fracture gradient results in a narrow mud weight window, especially when drilling close to overpressured reservoir. Well LD10-C was the first exploration well targeting at reservoirs in Meishan formation. Well LD10-A and LD10-B were offset wells in a distance of 15-20km drilled for reservoirs in Huangliu formation, which is above Meishan formation. During drilling, both wells encountered severe gas kick, mud loss and did not reach target.
In order to drill and complete well LD10-C safely, a real-time pressure monitoring solution was introduced with integration technique of logging while drilling (LWD) and look-ahead vertical seismic profile (VSP). It helped to monitor pore pressure and fracture gradient while drilling and predicted top of the overpressured reservoir. This enabled to keep the mud weight and equivalent circulation density (ECD) within a safe margin to avoid kick and mud loss, helped to set casing as close as possible to the top of reservoir. The reservoir section was drilled with a manageable mud weight window.
The main achievements of this task were: 1) accurately monitor and predicted pore pressure coefficient at reservoir. The predicted pore pressure coefficient was 2.25 SG versus 2.24 SG from actual measurement. 2) accurate prediction of reservoirs top. The predicted top depth of Sand C was 2m error with accuracy of 0.05%. The top depth of Sand D was 10m error with accuracy of 0.2%. 3) 12.25in section and 8.375in section was successfully drilled deeper with pressure monitoring. The 9 5/8in casing was set 491m deeper and 7in line was set 80m deeper than plan. As a result, well LD10-C was drilled and competed without any drilling complexities.
This was first application of LWD and VSP together for pressure monitoring while drilling in Yinggehai basin. The successful completion of well LD10-C confirmed that this integrated solution was an efficient technique to predict and reduce drilling risks, optimize mud weight and casing diagram, improve operational safety and save cost in HTHP offshore drilling.
Bioclastic Limestone Reservoir Characterization of an Oilfield in the Middle East
Authors: Lin Tengfei , Wang Nai , Wang Weijun , Li Nan , Yang Shuang , Liu Yumei , Dong Junchang , Zhang Qingchun , Guo Rui 
Published: April 2019

Abstract
Bioclastic limestone reservoir is playing a dominant role in the petroleum industry of Middle East. The oilfield in this paper belongs to long-axis asymmetric anticline. The S formation of Cretaceous period universally developed bioclastic limestone of carbonate platform system. It is the reservoir heterogeneity that severely limits the oilfield development.
We firstly analyze the lithofacies based on the core and thin section. Then the detailed well and seismic interpretation illustrate the sequence stratigraphy and facies analysis, and tectonic evolution are analyzed to restore sedimentary procedure from Palaeocene to late Pliocene stage. Ultimately, high quality reservoir of bioclastic limestone are depicted according to comprehensive analysis.
This paper offers reference and inspiration for bioclastic limestone reservoir: reef-beach complex and sweet spots in tidal-channel are dominant reservoirs for bioclastic limestone of Middle East.
Integrated Detection of Water Production in a Highly Heterogeneous and Tight Formation Using CRM Model: A Case Study on Water Flooding Gaither Draw Unit, Wyoming, USA
Authors: Liu Kailei , Wu Xingru , Ling Kegang 
Published: April 2019

Gaither Draw Unit is a heterogeneous and tight formation with an average permeability less than 0.1 mD. After more than 1.7 MMSTB water injection, there was no clear indication or benefit of the injected water from any producer. However, knowing the distribution of the injected water is critical for future well planning and quantifying the efficiency of injection. The objective of this study is to show how the Capacitance-Resistance Model (CRM) was used on this field and validated using other independent methods.
The CRM model describes the connectivity and the degree of fluid storage quantitatively between injectors and producers from production and injection rates. Rooted in material balance, signals from injectors to producers can be captured in the CRM. Using constrained nonlinear multivariable optimization techniques, the connectivity is estimated in the selected portion of the field through signal analysis on injection and production rates. In this tight formation, the whole field is divided into seven regions with one injection well and surrounding producers to conduct CRM analysis. We further use integrated but independent approaches to validate the results from CRM. The validation includes full field modeling and history match and fluid level measurement using echometering technology.
This paper focuses on a real field water flooding project in Gaither Draw Units(GDU). CRM is used to detect reservoir heterogeneity through quantifying communication between injectors and producers, and attains a production match. The fitting results of connectivity through CRM indicate permeability regional heterogeneity, which is consistent with full field modelling. The history matched full field model presents the saturation distribution showing that the majority of injected water mainly saturates the surrounding regions of injectors, and the low transmissibility slows down the pressure dissipation. Overall, the comprehensive interpretation obtained through these three independent methods is consistent, and is very useful in planning infill well drilling and future development plan for the Gaither Draw Units.
This paper shows that it is critical to integrate different sources of data in reservoir management through a field case study. The experience and observations from this asset can be applied to other tight formations being developed with water flooding projects.
Numerical Simulation and Experimental Study of Near-Wellbore Fracture Initiation Mechanism on Sandstone Coal Interbedding
Authors: Wan Liming , Chen Mian , Zhang Fengshou , Wang Li , Chen Wangang 
Published: April 2019

Abstract
With the development of unconventional oil and gas resources, the technology of commingling production in coal measure has been studied, which requires us to have a better understanding of the fracture near the wellbore in multi-layers. Previous studies mainly focused on the fracture morphology in a single layer and lack of 3D evolution role of microfracture propagation, so the fracture geometry in multi-layers of the coal seam and microfracture initiation near wellbore were studied in this paper.
In this study, the 3D-lattice model was used to simulate the 3D dynamic hydraulic fracture morphology near the wellbore in multi-layered coal based on XSite simulator, and the spiral perforation position was mainly studied. To verify the numerical simulation, the true tri-axial test system was implied for fracturing simulation experiments on the combination of coal, sandstone and limestone outcrops. The perforation position was changed to analyze the fracture morphology near the wellbore. Besides, the 3D scanning technology and the fracturing curve were used to study the fracture characters. As a result, the fracture morphologies near the wellbore in different perforation positions were studied.
The numerical simulation results showed that the microfracture evolution process in spiral perforation can be divided into three stages, (a) Stage 1: the vertical microfracture bands develop along the perforation hole; (b) stage 2: micro-annulus fracture forms around the wellbore; (c) stage 3: fractures break through along the perforation holes perpendicular to the minimum in-situ stress. The cleats and the natural fractures dominated the fracture initiation geometry when perforating in coal. The secondary branch fractures and the stepped fractures were the main characters in coal. Sandstone was a good barrier layer for the coal seam in fracturing, and the fracture in coal was easy to break through the limestone layer. When fracture initiated in coal layer, the fracture near the wellbore was complex with many secondary fractures, and the fracture surface was rough with poor continuity; when initiated in both sandstone and coal layers simultaneously, the main fracture developed quickly in coal and the smooth fracture surface formed near the wellbore.
The results of laboratory experiments were in good agreement with numerical simulation. The 3D evolution role of microfracture near wellbore could give a deep understanding of fracture complexity in near-wellbore area in coal. The experiments considered the actual formation combination, and the results of multi-layer fracturing could give a good guidance for field perforation optimization in the commingling of coal measure strata.
The Potential of Greenhouse Gas Emission During Flowback Process in Weiyuan Shale Production Site, China
Authors: Xue Ming , Fan Jun-xin , Weng Yi-bin , Cui Xiangyu , Li Xing-chun 
Published: April 2019

Abstract
Objectives/Scope: Greenhouse gas emission (carbon dioxide and methane, etc.) during shale gas production could decide whether it is a cleaner energy source than coal. However, the methane and carbon dioxide emission from flowback process during shale gas production remains unclear. The withdrawn of fracture water both from underground and surface water, and the relatively high gas pressure from the wellhead have made flowback water highly potential as a significant greenhouse gas emission source.
Methods, Procedures, Process: In this study, the estimation of greenhouse emission potential was provided based on the flowback water samples collected from shale production sites of China. The buffer capacity of carbon dioxide was estimated based on the parameters measured including temperature, pressure, conductivity, salinity, dissolved inorganic carbon (DIC), pH, chloride etc. The possible methane emission was also estimated based on the solution/dissolution curve from gas-water equilibrium during the flowback process.
Results, Observations, Conclusions: The results showed that: the relatively high salinity of the flowback water has provided a considerable buffer capacity for carbon dioxide. The water residence time in the water tank/pond largely determines air-water greenhouse flux. When the flowback water pass through the three-phase separator to the water outlet, the dissolution capacity of methane reduced sharply dropped. By switching to a higher water level in the separator, methane emission could be reduced. However, a higher water vapor ratio may be detected in the gas phase, as well. Besides the fugitive methane emission from pneumatic pumps, valves, etc., greenhouse gas emission from flowback water is a significant source which needs to be reduced in future shale gas production.
Novel/Additive Information: The determination of greenhouse gas emission from flowback could better defined the life cycle of shale gas, while provide baseline analysis for the development of greenhouse gas control technology during flowback water treatment and three-phase separator optimization.
New Low-Shock Low-Debris Gun Technology with Reliable Gunshock Simulation and Optimization
Authors: Baumann Carlos , Damm David , Escudero Jose , Smart Moises , Yang Xiang Tong , Liu Jun Yan , Wei Zhang 
Published: April 2019

Abstract
Many high-pressure/high-temperature (HP/HT) gas fields are developed in Northeast China with wells that have pressures reaching 20,000 psi and temperatures up to 180°C. The main difficulty in perforating these wells is the high wellbore pressure, which leads to large gunshock loads when the guns fire. Field operators experienced substantial losses when perforating these HP wells with standard guns; therefore, they needed to minimize the risk of equipment damage due to gunshock and reduce the amount of perforating debris left in the well.
To reduce gunshock loads and perforating debris problems, a new low perforating shock and debris (LPSD) gun system was developed specifically for HP/HT wells. Compared with standard guns, LPSD guns produce much less gunshock and negligible amounts of debris; thus, by using LPSD guns operators can minimize gunshock risk and save on cleanup runs. LPSD guns leave almost no debris in the well because LPSD guns retain all the metallic components inside the gun carriers, including the shaped charge cases, which remain virtually intact inside the guns. Complementing the new LPSD gun technology, we use gunshock simulation for shock load reduction and optimization. These are key elements of the perforating job design, and they are critical to prevent equipment damage in HP wells.
We show several examples of tool damage resulting from gunshock loads when third-party guns were used. These gunshock problems represented costly losses from equipment damage and nonproductive time. Using gunshock simulation, we show the origin of shock loads and the magnitude of the loads acting on the equipment, resulting in collapsed casing, corkscrewed tubing, and damage to packer mandrels and seals. We compared the performance of LPSD with standard guns under the same perforating conditions, demonstrating that LPSD guns can reduce shock loads significantly, making LPSD guns better suited for all HP wells, including those in Northeast China.
The LPSD gun system developed for HP wells significantly reduces the amplitude of the transient pressure waves and associated gunshock loads, and totally reduces the amount of debris. The reduction of gunshock enables perforating wells that otherwise cannot be safely and reliably perforated with standard equipment.
Prediction Methods of Key Development Indexes of Large Gas Fields Based on Big Data Analysis
Authors: Yuping Sun , Chunxiao Guan , Jingping Zhang , Qiaojing Li , Jialiang Lu , Hongjun Tang , Weijun Shen , Haibo Li , Hewen Zhang 
Published: April 2019

Large gas fields play an important role in natural gas industry. Recovery rate, plateau duration, recovery at the end of plateau, decline rate and recovery factor are the key development indexes for dynamic performance analysis and development planning. Scientific prediction for those indexes can support gas development planning strongly.
Through mining statistical analysis of 150 large gas fields and numerical simulation analysis, 23 objective influencing factors which affect the development effect are studied. Gas fields are classified according to the main influencing factors, and then the distribution of development indexes are summarized. Finally, a series of prediction methods for key development indexes are established.
Based on the above work, it is found that matrix permeability, drive types, reservoir architecture and fluid type are the most sensitive factors among them. According to the most sensitive factors, gas fields should be divided into 4 categories, and 13 subcategories and the distributions rules of development indexes of all categories are presented. Then new prediction methods for development indexes are established, including linear empirical formula method, similarity analogy prediction method based on Euclidean theorems, and probabilistic values method. In this process, according to the characteristics of influencing factors, logarithmic and piecewise function methods are used for dimensionless treatment, and the prediction accuracy of the methods is improved. Finally, the expert system software is developed which can automatically predict the key development indexes. The prediction accuracy is over 80% which can satisfy the requirement of strategic planning.
The new methods have the characteristics of multiple methods, applicable to multiple gas field types and predicting multiple development indexes. Those methods can be applied to predict the development indexes of new fields and evaluate the development effects of matured gas fields in batch.
Static and Dynamic Elastic Moduli of Bakken Formation
Authors: He Jun , Ling Kegang , Wu Xingru , Pei Peng , Pu Hui 
Published: April 2019

Abstract
In recent years, the exploration and production of oil and gas from Bakken formation in Williston Basin have proceeded quickly due to the application of multi-stage fracturing technology in horizontal wells. Knowledge of the rock elastic moduli is important for the horizontal drilling and hydraulic fracturing. Although static moduli obtained by tri-axial compression test are accurate, the procedures are cost expensive and time consuming. Therefore, developing correlation to predict static moduli from dynamic moduli, which is calculated from sonic wave velocities, is meaningful in cutting cost and it makes the unconventional oil and gas exploration and production more efficient.
Literature review indicates such a correlation is not available for Bakken formation. This may be attributed to the extremely low success rate in Bakken core sample preparation and not enough published data to develop correlation to relate dynamic moduli to static moduli. This study measures and compares the moduli obtained from sonic wave velocity tests with deformation tests (tri-axial compression tests) for the samples taken from Bakken formation of Williston Basin, North Dakota, USA. The results show that the dynamic moduli of Bakken samples are considerably different from the static moduli measured by tri-axial compression tests. Correlations are developed based on the static and dynamic moduli of 117 Bakken core samples. The cores used in this study were taken from the core areas of Bakken formation in Williston Basin. Therefore, they are representatives of the Bakken reservoir rock. These correlations can be used to evaluate the uncertainty of Bakken formation elastic moduli estimated from the seismic and/or well log data and adjust to static moduli at a lower cost comparing with conducting static tests. The correlations are crucial to understand the rock geomechanical properties and forecast reservoir performance when no core sample is available for direct measurement of static moduli.
Novel Methods and Test Fixtures for Comprehensive Evaluation and Characterization of LCM Products
Authors: Amanullah Md , Alouhali Raed , Arfaj Mohammed 
Published: April 2019

AbstractCharacterization, testing and evaluation of LCM products are very important for successful treatment of loss circulation problems. However, due to the lack of suitable API and any other industry methods and test apparatus that are applicable for characterization, testing and evaluation of various LCM products, the industry are facing difficulties in comprehensive characterization, testing and evaluation of LCM products. Hence, the industry needs fit-for-purpose methods and devices to fill up the industry gaps and overcome the technical limitations of current measurement systems. This paper describes several new methods and test devices for comprehensive characterization and evaluation of the stiffness characteristics of gel-based LCMs, attrition resistance of particulate LCM products, physical simulation and evaluation of sealing and blocking efficiency in fractured, super-K and vugular loss zones containing converging, diverging and parallel front fracture profiles.Experimental results provided by the characterization tools and various loss zone simulating test set up indicate the suitability of these tools and the apparatus in predicting the LCM Characteristics along with the sealing and plugging efficiency. Due to better simulation of various loss zone characteristic features, the newly developed test apparatus and the methods provide reliable technical guidelines to improve the probability and likelihood of success a LCM treatment job. The simple, easy to operate, reliable tools and methods described in this paper will help in overcoming the difficulties and limitations of testing and evaluation of LCM products to select the superior and reject the inferior.
Maximizing Production from Shale Reservoir by Using Micro-Sized Proppants
Authors: Lau Hon Chung , Radhamani Adiyodi Veettil , Ramakrishna Seeram 
Published: April 2019

Abstract
This paper describes the interaction between hydraulic fractures and the multi-porosity system of matrix porosity and natural fracture porosity in shale reservoirs. During the process of hydraulic fracturing, a complex fracture network consisting of primary and secondary hydraulic fractures as well as natural fractures is created. It is postulated that only shale porosities connected with this network will contribute to hydrocarbon production. Furthermore, we propose a way to maximise well productivity by injecting micro-sized proppants that are less than 150 μm (100 mesh) into the natural fractures and secondary hydraulic fractures to prevent them from closing and thereby increasing the stimulated reservoir volume. The size of the micro-sized proppant should be designed to be between one-seventh and one-third the aperture size of the natural fractures. In addition, various materials for micro-sized proppants are proposed and discussed. Of these, hollow glass microsphere shows more promise because of its light density and track record of being used as an additive material in the oilfield. Although limited laboratory experiments and field tests have shown encouraging results of using micro-sized proppants to enhance the productivity of Barnett shale, more research is warranted to optimize the use of these micro-sized proppants in production enhancement in various shale formations.
An Innovative Approach in Sand Onset Prediction at Different Water Cuts and Estimating Sand Production for Future Field Life
Authors: Baghdadi Faical , Gupta Anish , Hamid Aishah Sakinah A. , Madon Bahrom 
Published: April 2019

Abstract
Critical drawdown pressure for sand onset and its accuracy with change in water cut is a continuous area of study. The numerous parameters like grain cementation, viscosity of fluids, actual physics of sand production with fluids leads to a lot of uncertainty. In practical terms, it has been observed that these mechanisms lead to reduction in Uniaxial Compressive Strength of rocks. The objective of this paper is to present a novel method that not only helps on understanding the effect of water production on sand failure but to further predict the volumetric expected sand production up until a certain tolerable error.
A sand prone field within Malaysian region was identified and core tests were done to evaluate UCS and other rock strength parameters at different saturation of water to simulate the effect of water on rock strength. CDP evaluations were done and the values were calibrated with actual field data to have an accurate understanding of CDP values at different water cuts. Lastly, with the findings from field production data, limit was pushed further to develop a novel method to predict the volumetric sand production.
The proposed novel method has helped not only in understanding the effect of water production on sand failure but also on the amount of sand to be produced under different drawdown pressures with a reasonable accuracy. These results proved very useful in implementing Company's Holistic Sand Management strategy. The integration of this method with water cut predictions from reservoir simulation models helped the team to quantify the continue increasing sand production due to water cut increase. Company is replicating similar workflow in other sand prone fields for an effective sand management.
The approach is very novel as the theoretical modelling work has been effectively calibrated using real field data. This method has provided a high degree of confidence in estimating the amount of sand to be produced under different production conditions.
Authors consider this as a breakthrough in field of holistic sand management and very useful workflow for all other operators to emulate.