bluuebunny/crossref_metadata_2025_split huggingface dataset:
Assessment of Fly Ash as a Potential Demulsifier for Highly Stable Water-In-Crude Oil Emulsion Produced in the Petroleum Industry
Authors: Adewunmi Ahmad A. , Kamal Muhammad Shahzad 
Published: October 2018

Abstract
The quest for smart and cost-effective demulsification materials to separate water-in-crude oil (W/O) emulsions is highly desired in the petroleum industry. In this paper, an assessment study was conducted on the potency of coal fly ash (CFA) as a demulsifier for W/O emulsions. To our knowledge, this is the first study reporting CFA as a demulsifier for highly stable W/O emulsions. W/O emulsion samples were prepared without using any conventional emulsifier. Asphaltenes in the crude oil acted as an emulsifier and stable emulsions were produced. Six W/O emulsion samples of the same crude oil to water volume ratio (4:6) were formulated. A reference sample was selected for comparison during demulsificat ion. Demulsification tests were performed at room temperature (25 °C). Demulsification results obtained via the bottle tests showed that the reference sample (blank) without CFA remained stable without water separation after 48 hrs while the addition of various CFA quantities (1 % to 7 %) brought about separation of water from the oil phase. Separation of water was observed to have increased with increasing CFA addition in the emulsion. Water separation continued for each sample until around 24 hrs when equilibr ium was attained, and water separation remained constant. The W/O emulsion containing 7 % CFA displayed the highest performance with demulsifica tion efficiency (DE) of 96.67%. Demulsification comparison test results between CFA and a commercial demulsifier (poloxamer - 407) using same concentration and under room temperature showed that CFA was capable of separating water better than this commercia l demulsifier. This observation indicates that CFA can compete favorably with many commercia l demulsifiers available in the market. Additionally, the outcome of demulsification efficiency of 7% CFA at elevated temperatures (i.e., 60 °C and 80 °C) was around 98%. More importantly, the separated water at these elevated temperatures was clearer and contained lesser oil floccules than the separated water phase observed during demulsification tests conducted at room temperature (25 °C) condition. Shear rheology measurement reveals that CFA addition altered the viscoelastic characteristics at the crude oil/water interface at an aging time of 10 hrs and 55 mins. Viscous modulus remained stagnant while elastic modulus dropped significantly. Optical morphology revealed the phase transformation in the as-prepared W/O emulsion before and after the addition of CFA particles. The possible mechanism governing the demulsification of W/O emulsion driven by CFA particles was proposed. It is believed that this work will be relevant to petroleum exploration and refining operations.
New Insights Into Carbonate Matrix Stimulation From High-Resolution 3D Images of Wormholes Obtained in Radial Acidizing Experiments
Authors: Aidagulov Gallyam , Qiu Xiangdong , Brady Dominic , Abbad Mustapha , Onel Yener , Ewert Uwe 
Published: October 2018

Abstract
Usually, carbonate acidizing is studied by conducting linear coreflooding experiments in which a hydrochloric acid (HCl) solution is injected into small cylindrical core plugs, such as 1.5×6 in. (diameter×length) plugs. Results from these conventional experiments have provided extensive information on acidizing and wormholing mechanisms, but under conditions of essentially 1D flow along the axis of the plug. Meanwhile, field acidizing scenarios dictate radial (divergent) acid flow conditions around the openhole wellbore, and these conditions influence wormholing aspects such as initiation, branching, and death, in a way that cannot be simulated in linear coreflooding. In this study, we analyzed the results of large-scale radial acid injection experiments to advance understanding and characterization of wormholes created during matrix acidizing treatment.
We analyzed the results of high-energy X-ray CT scans for three 20×16×16 in. block samples of Indiana limestone from our recent radial acidizing experiments with HCl. CT scans were done for complete samples, and 3D images of internal dissolution patterns were built. Each 3D image consists of submillimeter-size voxels to capture fine details of individual wormholes.
The obtained 3D images of acidized blocks allow us to observe from various angles the details of the wormholes obtained in the three experiments, which demonstrated wide pore-volume-to- breakthrough (PVBT) range with three different injection rates. Also, variation of the CT number reveals the presence of depositional layers in all block samples, and the obtained CT images were used to interpret the effect that rock layers might have on wormhole penetration at different injection rates. Further, the built voxel models were used to calculate the radial distributions of dissolved rock volume, which otherwise are not obvious for such complex branched structures as wormholes. We observed how varied experimental conditions affected those distributions. The radial distributions were found very similar across the samples, which suggested the way to detect the effective wormhole penetration depth.
Radial acidizing experiments represent more closely the real conditions of wellbore acidizing; however, only a few radial acidizing experiments have been published to date. In this study, we enriched the results of our recent radial acidizing tests with high-resolution 3D CT images of the created wormholes which are quite rare considering the size of the acidized blocks. In the absence of field techniques to observe the wormholes downhole, CT images of the radially acidized laboratory samples provide valuable information about the appearance of wormholes, as well as quantitative data to validate models of wormhole growth and detection. Particularly, analysis of the obtained images showed how wormhole density responds to changing experimental conditions.
ASP Flooding: A Solution for Chemical Enhanced Oil Recovery in High Temperature, Low Salinity Reservoir
Authors: Hongyan Cai , Jie Cheng , Jian Fan , Hexin Luan , Qing Wang , Wenli Luo 
Published: October 2018

Abstract
Presently, field application of Alkali-Surfactant-Polymer flooding (ASP) has achieved great technical success with incremental oil recovery more than 20%. The synergistic effects induced by the three components, alkali, surfactant, and polymer greatly activate remaining oil after water flooding.
With the depletion of oil resources, ASP technique expanded to reservoirs having harsh conditions, such as high temperature, high salinity, low permeability, and heavy oil. For such oilfields, severe conditions bring great technical challenges to chemical agents, making it more difficult to obtain a suitable formulation than that in a conventional reservoir.
The ASP flooding feasibility study was conducted for a massive reservoir with high reservoir temperature ranging from 80 °C to 85 °C and low salinity less than 3000 mg/L. Various evaluations, including polymer testing, surfactant screening and evaluation, long term thermal stability, phase behavior were conducted in the laboratory. Then, the performance of optimized ASP formulation was tested by two runs of core flooding.
Through detailed in-lab study, thermal tolerant polymer and surfactant were selected with satisfying performance. Sound emulsification was observed in phase behavior study of Alkali-Surfactant (AS). ASP flooding utilizing weak alkali Na2CO3 was recommended for such high temperature, low salinity (HTLS) reservoir. Results from core flooding tests demonstrated an incremental oil recovery range from 16.89% to 20.38%. ASP shows promising technical potential for such low salinity reservoir.
Reducing Excessive Water Production Associated With Gas Hydrate Reservoirs Using a Thermal In-Situ Heating-Inhibitor Method
Authors: Fakher Sherif , Elgahawy Youssef , Abdelaal Hesham , Tonbary Ahmed El , Imqam Abdulmohsin 
Published: October 2018

Abstract
Gas hydrates are one of the most abundant sources of energy present today. They are formed at high pressures and low temperatures, and contain mainly water and methane. When dissociated, a large volume of water forms, much of which is produced. This research performs a simulation study on how to decrease the volume of water produced from gas hydrate reservoirs by utilizing an in-situ heating method combined with a low concentration thermodynamic inhibitor injection. Since gas hydrates form at high pressures and low temperatures, depressurizing the reservoir, or increasing its temperature would cause the solid hydrates to become unstable, and dissociate. The research begins by building a hydrate reservoir model using almost the same description of the models present in the literature in order to compare the results obtained. Several simulation runs were then performed using various production methods, several types of inhibitors, and finally testing and optimizing the newly proposed production method which combines thermal stimulation with inhibitor injection. The optimization process involves testing the novel method using 5-spot, 7-spot, and 9-spot production methods. The effect of each variable on the water recovery was studied, and the conditions under which the lowest water recovery were obtained. The highest water production occurred during glycol injection since it had the largest endurance to hydrate reformation and thus the largest water flow duration. When the glycol was combined with the thermal stimulation method however, the lowest water recovery was obtained. This is mainly due to two factors which include high rate of depletion of reservoir pressure, and the significant decrease in glycol concentration when used with thermal stimulation. This novel production method was chosen as the best method in terms of low water recovery based on a comparison of its recovery with that of all the other methods. The second task was to further optimize this method by introducing several well patterns and comparing their performance to that of the single well case. The largest number of wells, 9-spot pattern, was found to have the lowest water recovery due to the extremely high rate of reservoir pressure depletion. Gas hydrate production is still considered in its preliminary steps due to the complexity of hydrate reservoirs. By understating the mechanism by which these reservoirs can flow, and trying to reduce the excessive water production associated with these reservoirs a better understating of how to economically and safely produce from gas hydrate reservoirs is reached. This may lead to the utilization of this source of energy in the near future.
Optimization of Drawdown Pressure About the Ultra-Deep Fractured Carbonate Reservoir
Authors: Shuang-gui LI , Yu Chen 
Published: October 2018

Abstract
The original stress equilibrium of the formation is disturbed after borehole creation, and stress concentration is formed around the wellbore. During production, if drawdown pressure is too high, it will cause wellbore collapse and associated accidents. On the contrary, if the drawdown is too small, the production cannot meet the development needs. The ultra-deep fractured carbonate formation is tight and the in-situ stress is high. Dependent on the development of horizontal fractures and the degree of fracture filling and cementation, the distribution of UCS along the wellbore is quite different, leading to a larger variation of critical drawdown pressure. Meanwhile, different wellbore trajectories will result in different stress concertation around the wellbore and influence the critical drawdown pressure.
Furthermore, UCS of the rock will be reduced when the rock is soaked in completion fluids for a long time, and the critical drawdown pressure will be reduced. In view of these problems, this paper carried out a series of core tests, and developed a model to predict the critical drawdown pressure of uncased wellbores in fractured carbonate reservoirs. The influences of completion-fluid immersion and well trajectory on critical drawdown pressure is investigated. The results show that the critical drawdown pressure of vertical wells is less than that of horizontal wells. The critical drawdown of wellbores along the minimum horizontal principal stress is larger compared with wellbores along the direction of maximum horizontal stress. Completion-fluid immersion can cause a 4-5% reduction in critical drawdown pressure.
Advances in Non-Aqueous Drilling Fluid Formulations Through Innovative Surfactant Technology
Authors: Indulkar Sakshi , Thakur Swapnil , Asrani Megha , Singh Anil Kumar , Gupta Vivek , Patel Arvind 
Published: October 2018

Abstract
A number of problems such as emulsion instability, environmental issues and cost, persist in current liquid invert emulsifier technology of non-aqueous drilling fluids (NADF). These short comings are mainly due to incorporation of required components, solvents and mutual solvents in formulating emulsifier package, however they can be mitigated through innovative powdered emulsifier technology. This paper will present concept, design and chemistry of novel powdered emulsifier technology and compare their performance against current liquid emulsifiers.
New technology will include the development of solvent and mutual solvent free "solid state emulsifiers", and their applications in mitigating or eliminating the adverse effects of mutual solvents and other solvents which are incorporated in traditional liquid emulsifier technology. New technology in the form of advances made in emulsion technology, unique manufacturing technology of emulsifier additives and fluid formulations will be discussed.
NADFs have been used since their early introduction in late 1930s1, primarily because of their performance benefits when compared to water-based drilling fluids. Despite the performance advantages, NADF technology has not been without challenges because the complexity of drilling operations has grown enormously. These new challenges have required that NADFs be environmentally friendly, stable and possess desirable mud properties over broad range of temperatures and pressures, effective in broad range of applications and be cost effective. Through the constant efforts of research scientists in drilling fluid industry, advances have been made in NADF formulations, particularly in base fluids and surfactant technology to overcome or mitigate these challenges 2. However, the problems still exist. Various test we conducted for performance comparison of conventional liquid emulsifier and new technology solid state emulsifiers. After analysing the results, it was concluded that mutual solvents used in formulating liquid emulsifiers resulted in reduction of emulsion stability as much as 30%. The laboratory assessment, comparison and field applications of the newly developed powdered emulsifier technology will be highlighted. The development of this innovative powdered emulsifier technology has mitigated or resolved many issues, such as pour point, toxicity and other logistic problems to keep the NADFs at the forefront of the drilling fluid industry.
The paper will present newly developed concept and design of novel solid emulsifier technology to combat the associated challenges. These challenges include environmental issues, performance requirements, logistics and cost associated with current technology.
The Application of Fully Dissolvable Frac Plug Technique in Weiyuan Gasfield
Authors: Li Ming , Chen Lin , Wei Ran , Liao Chenglong , Fu Tao 
Published: October 2018

Abstract
Frac plug multistage fracturing technology is one of the main unconventional reservoir stimulation technologies. The fully dissolvable frac plug is a more efficient staged fracturing tool in compare with the fast-drilling frac plug. One of the most important advantages by using dissolvable frac plug is that the milling-out operation conducted in traditional plug is no more necessary, which significantly reduces the costs and risks of plug removal.
Weiyuan shale gas field is located in the southwest of China, most platforms have three-six horizontal wells. The blocking and sticking problems often happened due to the casing deformation or accumulation of sand in the wellbore. In this paper, the main technical challenges of fully dissolvable frac plug technology are analyzed. The field application of well A is described, including frac plug selection, field operation, the solutions under different blocking and sticking scenarios, sand flushing operation and problem analysis, etc.
The blocking and sticking problems happened in the process of tool string delivery. Then, corresponding solutions are prepared for the blocking and sticking problems before using the dissolvable plugs. Twenty-two fully dissolvable frac plugs and twenty-three fracturing balls were used in well A to complete twenty-three stages of fracturing. Field application results show that the fully dissolvable frac plug for multistage fracturing technology completes the reservoir stimulation safely and efficiently. The technology could meet the demands for pressure bearing performance and dissolving property.
This paper offers a case study that describes the application of fully dissolvable frac plug technology in long horizontal well of shale gas. It also provides an experience and reference case for engineers to develop other fracturing wells in unconventional reservoir.
A Review on Recent Developments and Progress in Natural Gas Processing and Separating Using Nanoparticles Incorporated Membranes
Authors: Amusa Abdulhameed A. , Ahmad Abdul Latif , Adewole Jimoh K. 
Published: October 2018

Abstract
This review paper centers on recent development and progress in natural gas processing and separation using nanoparticles incorporated membranes. Development of mixed matrix membranes (MMMs) is to enhance the performance of polymer membranes for CO2 separation. Overview of natural gas is illustrated. Abridged versions of MMMs development using an ideal polymer with corresponding nanoparticles are presented. The compatibility between nanoparticles with polymers is discussed. Finally, forecast on MMMs for future trends are highlighted.
Digital Transformation of PETRONAS' Hydrocarbon Production Allocation System (HyPAS)
Authors: Isa Edalawati Md , Salim Salmizana M , Ghani Ahmad Majdi , Karim Ili Izyan 
Published: October 2018

Abstract
This paper highlights the digital transformation journey of Malaysia's upstream hydrocarbon production allocation system. A standardized, web-based allocation system (herein referred as "HyPAS") was developed in place of two distinct medium used for different allocation network across Malaysia's region; namely the spreadsheet-based approach, and an age-old FORTRAN based system.
Optimization of the Annulus Nitrogen Injection Volume in Offshore Wells With Annular Pressure Buildup
Authors: Wang Hao , Zhang Hui , Li Jun , Zeng Yijin , Ding Shidong , Tao Qian 
Published: October 2018

Abstract
In the development and production process of offshore heavy oil thermal recovery wells, the rise of annulus fluid temperature will lead to extremely high annular pressure, which will threaten the casing safety and wellbore integrity. Nitrogen injection is often applied to release the annular pressure. However, insufficient injection can't solve the problem and too much nitrogen will lead to economic loss and poor effect. Therefore, there exists an optimal injection volume in nitrogen injection operation.
In this study, based on the thermodynamic principle and the PVT equation, the reducing mechanism of the nitrogen physical properties and injection volume for annular pressure was analyzed and a calculation method is presented. Then a well in Bohai sea of China is taken as an example to calculate the optimal injection volume and analyze the influence of nitrogen physical properties, annulus temperature and casing strength parameters on the optimal injection volume. At last, the prediction model of the optimal injection volume of annulus nitrogen and a safety evaluation method for production string under nitrogen injection are proposed and some optimization methods are given for nitrogen injection.
The results show that nitrogen injection can effectively reduce annular pressure over 40%. With the increase of nitrogen injection volume, the reduction rate of annular pressure and the injection efficiency decreases gradually. The optimal injection volume of annulus nitrogen is mainly determined by annulus temperature, intial temperature and pressure of nitrogen. Injecting nitrogen at the optimal volume can maximize the economic and safety benefit. It is necessary to control injection volume when taking nitrogen injection operation.
This work provides a prediction model for determining the optimal nitrogen injection volume to reduce annular pressure buildup, and a production string safety evaluation method was also proposed. These can provide guidance for field nitrogen injection operation.
Transient Pressure Behavior of Acid Fracturing Well in Tidal Flat Carbonate Reservoirs
Authors: Shi Wenyang , Yao Yuedong , Cheng Shiqing , Li He , Feng Naichao , Wang Yadong , Shi Zhiliang , Gao Min 
Published: October 2018

Abstract
Different from the marine carbonate reservoir, Tidal Flat Carbonate Reservoir (TFCR) rock contains Natural Fracture (NF) and Natural Dissolved Vugs (NDV). The NDV are usually distributed alone or along the NF in the rock core, which can be observe by the eyes. In the process of acid fracturing, Acid Fracturing Fracture (AFF) will activate NF and crack Carbonate Rock Matrix (CRM), acid fluid will etch NF and NDV. Finally, a complex Acid Fracturing Fracture Network (AFFN) with high conductivity is formed in Acid Fracturing Region (AFR). However, the range of the AFR is limited, there are still a lot of NF and NDV in Carbonate Rock Region (CRR).
The porosity and permeability of CRM are very low, the distribution pattern of NF and NDV are very complex. When pressure through the AFR and spread to the farther reservoir rock, the pressure behavior begins to show the multiscale flow characteristics. Therefore, the Non-Darcy Flow (NDF) of CRM in CRR and the Stress Sensitivity (SS) of AFFN in AFR need to be considered. Unfortunately, low porosity and low permeability in TFCR are seldom considered in typical transient pressure behavior model, such as NDF caused by Threshold Pressure Gradient (TPG) and SS caused by reservoir pressure decrease.
This paper presents a new transient pressure analytical model in TFCR, where the reservoir flow is subdivided into two flow regions: AFR and CRR. The effect of NDF in CRR and SS in AFR are both considered. Laplace transformation, perturbation method, Green function and Stehfest numerical inversion are employed to solve the model comprehensively. The model solution is verified with real transient pressure test data in TFCR. The effects of related influential parameters on transient pressure behavior, such as NDF, SS, acid fracturing area, rock property improvement degree and flow channel improvement degree.
Field example is conducted to shown the applicability of the new model, applied to the actual TFCR, the actual Bottom Hole Pressure (BHP) data of several acid fracturing wells pressure buildup test is well fitted. The results of this study can be helpful to better understand the flow mechanisms and transient pressure behavior of acid fracturing well in TFCR, which can be also used to evaluate acid fracturing measure and transient production performance. The judgement and recognition of the acid fracturing area and improvement degree have guiding significance for the repeated acidizing or hydraulic fracturing in the later stage of increasing production.