bluuebunny/crossref_metadata_2025_split huggingface dataset:
Development of New Degradable and Swelling Diverting Agent for Use in Low Temperature Hydraulic Fracturing Treatments
Authors: Sato Ken , Shinohara Kenji , Furui Kenji , Mandai Shusaku , Ishihara Chizuko , Hirano Yasuhiro , Taniguchi Ryosuke 
Published: November 2020

Abstract
It has been reported that hydraulic fracturing treatments with smaller cluster spacing and larger fracturing fluids volumes yield better production performance in Permian Basin, Bakken, and Eagle Ford. Degradable diverting agents can play an important role as temporary plugging materials for multiple, tightly-spaced fracturing operations. However, applications of degradable diverting agents are often limited to moderate to high reservoir temperatures. In this study, a new degradable diverting agent is developed for use in low temperature reservoir applications.
Butane-diol vinyl alcohol co-polymer (BVOH) which has controllable water solubility is evaluated as diverting agents for hydraulic fracturing treatments. Using a high pressure-high temperature filtration apparatus, filtration properties of BVOH diverting agents are measured for various powder-to-pellet ratios under a range of temperature conditions. Filter media with 1 to 3 mm width slots, that simulate fracture openings, are used for the filtration test. The filtrate properties are evaluated based on spurt losses and filtration coefficients for quantitative evaluation. An analytical diverting agent model that considers swelling of the polymer in water is also developed for evaluating the filtration process of multimodal particles.
The experimental results presented in this work indicate that the degradable BVOH materials can be used as effective plugging agents for fracture-like narrow slits. Based on spurt losses and leakoff coefficients obtained under different powder-to-pellet ratios and temperature conditions, the performance of the diverting agents is quantitatively evaluated. The optimum powder-to-pellet ratio for BVOH materials are determined to be 80 to 20. The experimental results also reveal that the degree of BVOH crystallinity provides a dominant effect on the solubility of BVOH powder. The test results also indicate that the diverting agent plug properties started degrading under the temperature greater than 140°F as designed. The BVOH diverting agent developed in this work provides effective diversion effects under low to moderate temperature conditions (e.g., 80 to 100°F). The analytical plugging and bridging model developed in this work, which takes into account swelling properties of the polymer, show very good matches to the experimental results.
The degradable diverting agent developed for low temperature applications improve operational efficiency and economics of multistage hydraulic fracturing treatments in shallow reservoirs and operations where immediate fracturing fluid flowback is required. The plugging and bridging model with bimodal particle system developed in this study helps stimulation engineers select and optimize diverting agent material types, particle size distribution, and diverting agent concentration for various well, stimulation, and reservoir conditions.
Novel High-Effective Component for Acidizing Corrosion Inhibitors: Indolizine Derivatives of the Quaternary Quinolinium Salts
Authors: Yang Zhen , Wang Yefei , Finšgar Matjaž , Hu Huayou , Wu Jiajia , Zhan Fengtao , Sun Shuangqing , Ding Wengang 
Published: November 2020

Abstract
Acidizing is a widely used method for the well stimulation and Corrosion inhibitors (CIs) are essential in acidizing fluid to mitigate corrosion of metallic equipment. This calls for high-effective CIs as the demands for oil and gas still increases. This paper introduces several new protective indolizine derivative compounds with remarkable inhibition effectiveness under high-temperature acidizing condition. The indolizine derivatives were obtained facilely through the cycloaddition (at about 80 °C, alcohol as a solvent) procedure from the conventional quinolinium salt. Chemical structures of the derivatives were confirmed by instrumental analysis methods including NMR, MS etc. The corrosion inhibition properties of the indolizine derivatives were investigated and evaluated by weight loss test, electrochemical methods (Tafel curve and EIS), in comparison with their quaternary quinolinium precursors. Corrosion inhibition behavior of the derivatives in acid was simulated by DFT study. The thermodynamic aspect of the inhibition were also investigated. Experimental results showed that very low dosage of indolizine derivatives exhibit excellent inhibition efficiencies for the N80 steel in corrosive medium. Apart from the good solubility and thermo-stability in aqueous acid solution, the indolizine derivatives even showed eco-friendly advantages by presenting a much lower EC50 values than the other CIs. Compared with the conventional acidizing CIs, the composite indolizine derivative derived inhibitor mixture can dramatically mitigate the corrosion even at low amount of the mixture added, especially for those tests conducted at the bottom-hole elevated temperatures. The amazing inhibition of novel indolizine derivative with organic or inorganic components reveals that the mixture could be utilized as new effective CI for acidizing in concentrated hot acid. The inhibition of series traditional quinolinium salts would get greatly improved after they have get converted into the corresponding indolizine derivative inhibitors, which provides enlightening thoughts for developing novel high-effective CIs. The use of these compounds may offer a creative new choice for strong acid medium corrosion in petroleum engineering and showing good prospects in replacement of the current main components of acidizing CIs in the near future.
Pressure Transient Analysis in Fractured Horizontal Wells with Three-Dimensional Flow: Case Study
Authors: Dong Peng , Chen Zhiming , Yi Xinbin , Wang Tianyi , Liao Xinwei , Chu Hongyang 
Published: November 2020

Abstract
Pressure transient analysis in fractured horizontal wells in unconventional reservoirs has received much attention in last two decades. A large number of microseismic data showed that many hydraulic fractures do not actually penetrate the entire formation, which means that 3D flow into the hydraulic fractures should be considered. However, there is limited work on analytical method based well-testing models for fractured horizontal wells with 3D flow. To improve this situation, a semi-analytical model for the horizontal well with partly-penetrated multi-state fractures are developed with considering 3D flow, based on fracture discretization. The new model proposed in this paper can describe more complex 3D flows in the multiple hydraulic fractures.
With flow regimes analysis and field application, it is found that the pressure derivative curves of fractured horizontal wells with 3D flow are complex. The most obvious feature of the flow regimes is that the curve appears to drop after the linear flow. It behaves like a second "hump" occurs in the pressure derivative curve. This is due to the fact that fractures do not penetrate the formation completely, and a pseudo-spherical flow occurs at this stage. The pseudo-spherical flow is more obvious when the fracture height is small or the fracture is short. Evaluated results from field application are basically consistent with the overall understanding of the MH shale oil reservoirs, which demonstrates the reliability and practicability of the proposed model. The evaluated fracture conductivity is less than an ideal value, because the fracture conductivity declines rapidly with the high reservoir pressure. This work helps to better understand the pressure transient behavior and to facilitate fracture evaluation in the unconventional reservoirs.
Automated Pattern Recognition as a Temporary Replacement for Downhole Gauges
Authors: Lyall John , Watt Andy , Murphy Chris 
Published: November 2020

Abstract
Automated pattern recognition with basic, high-level coding can be readily applied to petroleum production surveillance to reduce the impact of equipment failure. Machine learning is an application of regression techniques that range in complexity from simple linear regressions to convolutional neural networks. This paper outlines a machine learning based solution that was developed for a common petroleum engineering problem.
A temporary proxy for downhole pressure measurements was developed after gauge failure on an offshore gas production well. A solution was found in the machine learning space by applying multivariate linear regression to represent relationships within the production system. The workflow presented is based on Python code using the open source SKLearn library. Readers should carry out their own independent assessment of the approach outlined in this paper (including the model development procedure pseudo code set out in Appendix B and Python code example set out in Appendix C) in the context of their own specific requirements and circumstances before deciding to use any aspect of the approach (or Python code).
The method uses available production data (known conditions of pressure and temperature from the wellhead and further downstream, choke settings and well total mass flow rates) to predict an unknown downhole pressure. The failure of a downhole gauge was simulated by removing the downhole data from the dataset at a certain point in time. The machine learning model was trained using 19 months of well production data. The nine months that follow was then entered under gauge failure conditions (with downhole data removed), to predict downhole pressure from other production data. The result was a downhole pressure prediction within 0.2% (40 kPa) of the actual gauge measurement up to nine months after the simulated gauge failure.
The prediction was compared to downhole pressure estimations that were calculated with a conventional physical model. The machine learning model outperformed the conventional physical correlation over the test period. The model was validated as an adequate short-term replacement for downhole pressure measurement for an offshore gas well. The solution delayed disruption to the management of reserves, enabled the continuation of production forecasting and postponed subsea intervention.
This paper also provides a foundation for assisted trend analysis, in which a gauge that is identified as drifting from the long-term trend can aid in the detection of physical changes such as water breakthrough.
Improving Shale Wellbore Integrity through Membrane Efficiency and Geomechanics Solutions
Authors: Buranaj Hoxha Besmir , Ettehadi Reza , Porter Justin , Prasad Umesh , Ong See Hong 
Published: November 2020

Abstract
Drilling through shale is an inevitable endeavor for both conventional and unconventional oil and gas reservoirs, where for the latter acts as a source and trap rock – substantiating its position in operational difficulty. Shale formations tend to be anisotropic and typically characterized by high in-situ stresses. In certain shales, geomechanics is very important in understanding how to stabilize the wellbore. Overall, it can prescribe a correct mud weight (or rather the overbalance) to provide the mechanical stability (stress-induced). However, this over-balance can be rapidly destroyed due to the rise in shale pore pressure associated with the different potentials (hydro-, chemo-, thermo-) acting at the shale-fluid interface. These ‘potentials’ can have an effect on the borehole stability, where in several cases, create phenomena that are just recently being wholly understood.
From a chemo-mechanical perspective, designing the proper fluid that will maintain the stability of shale formation, over time, requires the knowledge of membrane efficiency that is crucial for the geomechanical effects on the wellbore. However, in current industry practices there are limited studies that integrate geomechanics with comprehensive drilling fluid properties. Typically, inputs are arbitrary assumptions when utilizing geomechanical software. Classic workflow during geomechanics design includes selecting suitable mud-weight window which do not exceed the fracture gradient (to prevent losses) or remain well above the collapse pressure (or pore pressure) whichever is more suitable to prevent kicks or blowout.
The work presented herein takes the workflow a step further, by introducing key parameters of relevant shale characteristics/behavior to current geomechanical software to provide more accurate wellbore stability simulations as a function of fluid properties (i.e. membrane efficiency). Two different shale types, Mancos and Pierre shale II, which significantly vary in their physical, chemical, mineralogical, and mechanical properties are selected for wellbore stability analysis. The methodology consisted of three phases, (1) shale characterization, (2) pore pressure transmission and membrane efficiency calculations, (3) wellbore stability simulations via geomechanics software. The software is an integrated software used to assess stress and wellbore stability by calculating a "borehole stress and failure orientation" module to perform concurrent simulations to determine stability parameters (mud weight, fluid activity, membrane efficiency) needed for drilling through complex shale.
Development of a New Oriented Perforating System for a Challenging Subsurface Environment
Authors: Haigh Mike , Morrison Alan , Crabtree Phil , Doornbosch Fokko 
Published: November 2020

Abstract
The Gorgon Stage 2 (GS2) project is a brownfield expansion of the existing Chevron-operated Gorgon Foundation Project (GFP). GS2 will maintain gas supply to the Gorgon liquified natural gas (LNG) plant by expanding the existing infrastructure with additional subsea wells in the Gorgon and Jansz-Io gas fields. Low installation risk and high life-cycle reliability were primary objectives of the GS2 well completions due to the high costs associated with subsea installation and intervention. The Gorgon subsurface environment is hostile with temperatures reaching 165°C, high concentrations of CO2 and predicted sand production. The risk to long-term sandface completion reliability is reduced significantly when the perforations are aligned toward the plane of maximum stress. To achieve the primary well objectives the GS2 project team selected shoot-and-leave, cased hole, oriented perforating (CHOP) as the Gorgon completion design.
Chevron partnered with a leading supplier of tubing-conveyed perforating (TCP) equipment to develop a highly reliable, internally oriented perforating system manufactured from corrosion-resistant alloy (CRA) material, an industry first. The development and engineering phase consisted of defining project requirements, component design, manufacture of test equipment, testing, and system integration tests. Charge testing was conducted under reservoir conditions to verify that perforating performance met minimum requirements. Other tests included verification of gun orientation accuracy at Gorgon down-hole temperatures, a significant undertaking by the TCP supplier.
Testing and qualification activities were performed at the TCP supplier's technology center with local Chevron oversight. Quality assurance (QA) procedures were revised to be more aligned with those typically used for completion equipment, because in the industry, TCP equipment has traditionally relied on vendor-specific QA procedures and in-house oversight. Quality plans were updated to reflect the changes and enable third-party inspection (TPI) during product manufacturing.
This paper will share the collaborative efforts of Chevron and the TCP supplier to design and qualify a CRA oriented perforating system and answer important questions such as "How will we build confidence that the TCP guns will orient correctly?" and "Will the perforating charges perform as required under Gorgon down-hole conditions?"
Influences of Proppant Embedment and Deformation on Micro-Sized Graded Proppant Injection Scheme
Authors: Liu Huifeng , Li Jiaxue , Xu Zhixiong , Yuan Zebo , Liu Jv , Ren Dengfeng , Feng Jueyong 
Published: November 2020

Abstract
The method of micro-sized graded proppant injection has been proposed in the industry to increase the size of the stimulated zone in naturally fractured reservoirs, especially CBM. However, big discrepancies between the modelling results of graded proppant injection and the experimental results have been observed. An analytical model of graded proppant injection with consideration of proppant embedment and deformation is established in this paper, and the influences of proppant embedment and deformation are investigated.
An analytical model of calculating the permeability of a fracture filled with partial monolayer proppant is established, and a linear elastic model of calculating proppant embedment and deformation is coupled into it to investigate the influences of proppant embedment and deformation on propped fracture permeability. The influences of proppant embedment and deformation on propped fracture permeability and the optimal proppant packing ratio are investigated. The influences of properties of proppant and rock on propped fracture permeability and the optimal proppant packing ratio are also studied. The graded proppant injection schedules with and without consideration of proppant embedment and deformation are compared and practical understandings are obtained.
The results show that the propped fracture permeability is reduced by more than 50% when the embedment or deformation extent reaches 18%. Neglecting proppant embedment and deformation will lead to an under-estimation of 15%-18% for the optimal proppant concentration during graded proppant injection. Proppant diameter has little influence on the optimal proppant packing ratio. Lower Elastic Modulus in the proppant or rock and/or smaller proppant particles leads to a higher optimal proppant packing ratio and lower permeability correction factors. Poisson's ratio of proppant or rock has very little influence on both optimal proppant packing ratio and permeability correction factor. Proppant concentrations at different stages of graded proppant injection with consideration of proppant embedment and deformation are 21.8% higher than those neglecting the two factors. Proppant embedment and deformation must be considered during planning of the graded proppant injection schedule.
Field Application of Nano Polymer Microspheres Profile Control: A Pilot Test in Ultra-Low Permeability Oil Reservoir
Authors: Hou Ganggang , Yuan Xinyu , Han Penggang , Lu Fan , Jiao Zhen , Diwu Pengxiang , Liu Tongjing , Hou Jirui 
Published: November 2020

Abstract
During the development of low permeability oil reservoirs, the problems of rapid breakthrough of water, non-uniform water-absorbing of injection well and the low efficiency of water flooding are usual facing. The application of polymer microspheres (PMs) for in-depth profile control is considered to be an effective method to solve these problems. This paper systematically reports a field application case of nanoscale PMs for in-depth profile control in the ultralow permeability oil reservoir. In the paper, the characteristics of static geological and dynamic production of Block A in Changing oilfield are analyzed in detail. Meanwhile, the production history and facing problems of the Block A are clarified. According to the analysis results, the pilot test area for the application of PMs in-depth profile control is selected, and its characteristics are described. Then, a detailed implementation scheme is made for the pilot test area. Finally, according to the evaluation parameters of production wells and injection wells, the performance of PMs in the pilot test area is evaluated. The performance evaluation results show that the application of PMs in the pilot test area is very successful, and the PMs can be used for in-depth profile control in the ultralow permeability oil reservoir. More specifically, the average injection pressure of single well increased by 1.1 MPa, and the average thickness of water absorption layer increased by 1.2 m after PMs injection. The success ratio of in-depth profile control was 37.3%, and the total oil production increment of production wells was 4609.2 t. In addition, comparing the performance of well groups that use the PMs with different calibration diameter, it indicates that the application of PMs with appropriate particle size and the reasonable implementation schemes are critical to the success of in-depth profile control. For the pilot test area, the PMs with the calibration diameter as 300 nm is more suitable.
New Cementing Spacer Technology Cures Total Lost Circulation in an Offshore Exploratory Well
Authors: Abad Juan , Ekwue Ann-Marie , Bermudez Francisco 
Published: November 2020

Abstract
During the drilling process of exploratory wells, the formation data is often limited; most of the time drilling engineers must estimate the pore pressure and fracture gradients. This information is critical for designing the drilling fluid, spacers, and cement slurry as to provide the necessary density and rheological properties.
An error in estimating the pore pressure or fracture gradients can induce wellbore instability and lost circulation. If these losses are not controlled, during the cementing job the programmed top of cement (TOC) will not be achieved, zonal isolation will be compromised, and the casing string will not be fully supported. These problems can lead to additional expenses such as remedial jobs, non-productive rig time, use of additional materials, costly logistics, etc.
This paper presents a case history with a critical cementing job in which the operator was drilling an offshore exploratory well in Southern Mexico when an area with constant gas flow with a narrow pore-pressure to fracture-gradient window was encountered. The operator had to increase the density of the drilling fluid, which in turn induced total losses.
The cementing company recommended pumping a unique spacer technology that enabled circulation to be regained while pumping the cementing job. This technology is an ultra-low invasion cementing spacer that creates an impermeable barrier on the face of the formation through differential pressure. This barrier helps to isolate the formation from the total equivalent circulating density (ECD), thus allowing circulation even in situations where the ECD approaches or slightly exceeds the fracture gradient.
Experimental Study on the Impact of Supercritical CO2 Soak Pre-Treatment on Re-Fracturing of Shale Oil Reservoirs
Authors: Tao Jiaping , Meng Siwei , Cao Gang , Gao Yang , Liu He 
Published: November 2020

Abstract
Initial hydraulic fracturing of shale oil reservoirs has often resulted in disappointing results, with low connected volumes and productivity degradation with depletion. To improve the single well production and oil recovery, re-fracturing techniques have received increased attention, but face the challenges of economy, applicability and feasibility.
In this paper, the propagation mechanism during re-fracturing operations is explored through laboratory experiments. Firstly, mechanical analysis and fracturing simulation experiments were performed using the formation cores. After the fracturing simulation experiment, the fractured core was soaked in supercritical CO2 to enhance the re-fracturing effect. Then a re-fracturing simulation experiment was performed to analyze the fracturing propagation mechanism. Meanwhile, some new cores are soaked into supercritical CO2 to explore the changes of mechanical properties under different soak time.
The mechanical analysis experiment showed that supercritical CO2 soak has a strong influence on the uniaxial compressive and tensile strength of shale. With an increase of soak time, both the compressive and tensile strength clearly decreased. During the first fracturing operation, fractures propagated only along the horizontal bedding and could not open the rock matrix. After supercritical CO2 soak, re-fracturing could open the horizontal bedding more easily as well as extend to the rock matrix, creating a more complex fractured system, enhancing oil recovery.