bluuebunny/crossref_metadata_2025_split huggingface dataset:
Study on the Correlation Between the Hydrate Formation-Blockage Risk and Gas-Liquid Flow Pattern in Horizontal Pipelines
Authors: Liu Wenyuan , Hu Jinqiu , Sun Fengrui , Sun Zheng , Li Xiangfang 
Published: November 2019

Abstract
Hydrate formation and blockage in pipelines are serious problems in the oil-gas production and transportation. The current research is limited to the prediction of pipeline hydrate formation. However, the small hydrate generation often does not form obvious pipeline flow-barriers. Therefore, compared with hydrate formation, hydrate growth rate and deposition rate is equally important for the emergence of flow barriers. Based on the hydrate formation-growth-deposition mechanism and combined with the hydrate experiment in the flowloop, the characteristics of hydrate formation-growth-deposition in pipelines under different gas-liquid flow patterns was studied. The results show: Different flow patterns show different hydrate formation and deposition characteristics due to different phase distribution and interface distribution. The bubble flow, cluster flow and slug flow have some similarities in flow patterns. It can be seen that the gas phase in the flow system exists in the form of bubbles, and the occurrence of thin liquid film on the tube wall under these three flow patterns is relatively rare; accordingly, the similarity of laminar flow, wave flow and annular-mist flow shows that thin liquid film or gas-liquid-pipe wall three-phase interface will always appear in the flow process, which will make the hydrate formation and deposition risk of the latter three flow patterns significantly greater than the former three flow patterns. Comprehensive analysis shows that the hydrate risk of each flow pattern is in the order of annular-mist flow &gt; laminar flow and wave flow &gt; slug flow &gt; cluster flow and bubble flow. The annular-mist flow is the most dangerous flow pattern for hydrate formation and blockage, which is quite common in the oil and gas industry. In this case, special attention should be paid to hydrate prevention and control.
It is hoped that the research in this paper can provide some theoretical guidance for field construction and related researchers.
A Novel Approach in Handling Water Breakthrough in Fractured Carbonate Reservoir Through Dynamically Integrated Fracture Characterization: A Case Study
Authors: Farias Rodriguez Leopoldo , Funk Erich 
Published: November 2019

Abstract
A key management guideline for water-driven, naturally fractured reservoirs (NFR) is to minimize water production. Water breakthrough is undesirable as it reduces oil production rate and lowers oil recovery. Managing these reservoirs involves delaying water breakthrough and mitigating its effects. This paper describes a cross-disciplinary workflow, which serves such purposes by making use of downhole pressure gauges (DHG) pressure data-based well models along with a dynamically validated fracture model.
The data-based well model is developed from our DHG pressure-production database. It has been field tested for forecasting water breakthrough, predicting water level in wells and planning for counteractive actions. The data-based well model is combined with a detailed fracture model whose elements were derived from the systemic integration of fracture types, genetic context and interaction with the carbonate host rock during diagenesis. The resulting workflow enables the well and reservoir management team (WRM) to put the well back in production after water-breakthrough in a way that maximizes oil re-saturation from tributary fractures into the main conductive features connected to the wellbore.
A field case illustrating the application of this workflow is discussed. The outcome of the application of this workflow is compared with the performance of other wells in which water breakthrough was dealt with by merely reducing their liquid rates till water cut became manageable. A complete set of relevant measured data, including downhole pressure gauge and a post breakthrough production logging tool (PLT), is discussed in the paper. Well performance puts in evidence that the workflow discussed in this paper allows for higher oil production rates and significantly lower water production rates following water breakthrough compared against more traditional approaches for handling wells after water breakthrough.
The workflow was developed through frequent iterations between near-wellbore flow performance data-based modeling and multi-scale fracture characterization, aimed to address the impact of the main conductive features and tributary fractures on well productivity. It is of interest to anyone involved in managing NFR, especially those engaged in preserving the sustainability of the oil potential of the well (both duration and rate).
Acid-Fracturing Techniques as a Good Alternative to Help Improve Field Development Assets
Authors: Petriz Munguia Jose Maria , Gonzalez Valtierra Blanca Estela , Trujillo Hernandez Javier , Santos Sarai , Campos Monroy Katya 
Published: November 2019

Abstract
Acidizing and acid fracturing techniques are routinely used in two important formations in the marine regions of Mexico, the Jurassic and Cretaceous formations. These formations are naturally fractured carbonate and dolomite reservoirs having a permeability in the range of 0.19 to 22 mD, porosity from 2.8 to 6%, approximate bottomhole temperature (BHT) up to 177°C, pressure (BHP) of 10,374 psi, and a crude of 45° API. Using acid fracturing techniques helps improve the development of these assets. This paper shows the results of more than 40 acid fracturing operations performed in recent years.
Depending on the productivity evaluation, wells belonging to these assets are stimulated as part of the completion stage. Because of their low permeability, a common approach is to perform an acid fracturing operation. As a first evaluation, a minifrac test is executed to obtain the necessary data to calibrate the acid fracturing simulation model. After this step is performed, the acid fracturing design is evaluated. Generally, a sustained production acidizing technique is used for conductivity enhancement and closed-fracture acidizing is also included as a tailored treatment with an all seawater-based acidizing system.
For these operations, an average five-fold increase in oil production has been observed after treatment. In some cases wells in the completion stage, having no production before treatment, delivered up to 7000 BOPD after treatment. In these low-permeability assets, the post-fracturing response shows good results in general terms, increasing final conductivity in the near-wellbore area, and improving the production in these wells. The fracture gradient observed varies from 0.715 to 0.981 psi/ft with an average minimum stress of 13,670 psi. To perform the acid fracturing treatments, an average of 6400 hydraulic horsepower (HHP) must be available, with up to 13,400-psi surface pressure observed. As such, a stimulation vessel is necessary in all operations, applying a 26-bbl/min average pumping rate.
Globally, acid fracturing treatments are a common stimulation technique. This study shows that stimulating proper candidates in Mexico using acid fracturing significantly helps increase production, which may be relevant for the exploitation of new areas where fracturing has not been implemented.
Case Study: Enhance Fracture Complexity And SRV For Strong Heterogenous Shale Reservoir In Weiyuan Gas-field, SW China
Authors: Zeng Lingxiang , Liu Zhuang , Zheng Yunchuan 
Published: November 2019

Abstract
The major challenges of shale reservoir development in Weiyuan gasfield are: (1)strong geologic heterogeneity, such as geo-stress, horizontal lamination, limited complexity and propagation of hydraulic fracture; (2)casing deformation, which caused the reservoir fractured insufficiently for many engineering problems. To avoid the problem above and increase complexity and SRV of hydraulic fracture, a deeply fracturing technology (DFT) was proposed, which was validated available and had been applied in 20s wells.
Based on ununiform distribution of geo-stress, the mechanism of DFT is using temporary plugging materials to fracture the reservoir sufficiently, which can be classified in 3 major patterns, include Intrasegment/Multi-segments/Closely spaced fracturing. Firstly, according to reservoir and stimulation objectives, choosing the appropriated development pattern. Then, considering geological and engineering factors, the optimization of temporary plugging materials and pumping parameters are needed in making pumping schedule. Finally, conducting fracturing by the schedule, and combined with operation curve and micro-seismic data, choosing proper time to release temporary agents.
With the application in the field, some conclusions are as follows:(1) Intra-segment development pattern was preferred in single-segment sufficient simulation; multi-segment was favored in the development of multi-stages without bridge plug situation, especially in the stimulation of casing deformation intervals. Which also improved operational timeliness; Closely spaced perforation pattern was benefit for the segment with big geo-stress difference and the well with small well spacing.(2) DFT was validated available by fracturing curve and micro-seismic monitoring. Event response points coverage rate of segment was 100%, SRV per segment and micro-seismic events were increase by 11%-45% and 54%-429%, respectively.(3) A combination of temporary plugging ball and powder was recommended, and the optimal agents pumping rate was 3m3/min. With the treatment above, pumping pressure was increased after agents released, the peak increment is 10 MPa, plugging effect was clear.
DFT is suitable for high heterogenous horizontal interval development, and also can be combined with bridge plug to achieve segment sufficient fracturing. The most important is, it is available in casing deformation interval stimulation, which is so serious in Weiyuan gas-field.
Scoping Model Study of Carbon Capture and Storage for Enhanced Oil Recovery for the Zarrarah Oil Field in UAE
Authors: Mheibesh Yazan Ghassan , Fraim Michael , Sultan Abdullah S , Al Shehri Fahad Hassan 
Published: November 2019

Abstract
The purpose of this scoping model study of Zarrarah field, with ~14 BSTB, and ~30 TSCF OIIP and GIIP respectively, was to show that natural gas cap could be used in a zero emission power plant to generate electricity, produce NGLs, and capture carbon dioxide gas. Over the lifetime of the project, the injected CO2 gas will displace the oil column in the heterogeneous carbonate rock system in a miscible gravity dominate mode.
Petrophysical data needed to construct a simulation model for Zarrarh field was collected from literature review. We used 12 analogous rock types from neighboring fields of Asab and Bu Hasa. The CMG-GEM reservoir model used 18 components to describe the fluid properties and to verify no asphaltene drop out near the producing well bore. The model was calibrated on total field oil production and gas oil ratio and then various CO2 flooding scenarios were tested to optimize recovery and minimize gas coning in the horizontal well flooding patterns.
The current production method for Zarrarah field is gas cap expansion with recycling of lean methane gas into the gas cap for pressure maintenance and recovery of NGLs. The averaged over the heterogeneous rock type regions, the miscible CO2 flood recovered at least 20% additional oil for each reservoir sector. The percentage of produced NGLs from the total in place will increase from 23% to 36% over the lifetime of the project with CO2 extraction. This production method will also supply for UAE and KSA at least 20 GW of zero emissions electric power for the next thirty years. CO2 reduces the oil viscosity and reduces gas coning by swelling the oil in the natural fractures system. The optimal CO2 injection technique is flank injection starting at the northern end of Zarrarah field. At the end of project life, the CO2 gas reserves should approach 30 TSCF to flood other reservoirs in the Empty Quarter such as Shah oil field.
The novelty of this work is designing the first economic and zero emission power plant for EOR in KSA and UAE. Generating the first economic man-made CO2 storage reservoir for future miscible oil recovery in the Empty Quarter. The increased NGL recovery will help supply the feed stock for the petrochemical industry for the next 30 years. This technique has also the ability of providing a fresh water source for low salinity water flooding or local inhabitants.
Thermoelastic Fracturing on Water Injectors as Part of Injectivity Enhancement in Giant Offshore Carbonate Field. Case Study
Authors: Sarsekov Arlen 
Published: November 2019

Abstract
Water Injection is part of secondary recovery mechanism which aims to increase oil recovery by increasing or maintaining the reservoir pressure and provide additional pressure support.
Most of the time water injection is controlled under matrix injection below the fracture pressure in order to avoid the creation of fractures and risk of bypass oil. However, there are two different mechanisms of fracture creation in water injection: poroelastic fracturing and thermoelastic fracturing. First one will activate above fracture point, while the second one creates below the original fracture point and most of the time missed in reservoir field development
Normally fractures can be categorized in 3 groups: –Fractures induced due to increase of injection pressure above pore pressure. (Poroelastic fractures)–Fractures induced due to drilling activities (Overbalance drilling)–Fractures induced due to injection of cold water.
Fractures which are induced due to difference in temperature between injected fluid and rock fluid called thermoelastic fractures. Thermoelastic fracturing is controlled primarily by the difference in temperature between reservoir rocks and injected fluids. This paper will focus on thermoelastic fractures and its propogation along the formation.
The analysis performed in a giant offshore carbonate field in Middle East on a well level as well as field level through injection modules.
This paper will describe the mechanisms of thermoelastic fracturing and methodology to identify this type of fractures in water injectors through several cases studies.
Water Flooding Performance Prediction in Layered Reservoir Using Big Data and Artificial Intelligence Algorithms
Authors: Chen Cunliang , Yang Ming , Han Xiaodong , Zhang Jianbo 
Published: November 2019

Abstract
Managing oil production from reservoirs to maximize the future economic return of the asset is an important issue in petroleum engineering. One of the most important problems is the prediction of water flooding performance. Traditional strategies have been widely used with a long run time and too much information to solve this problem. Therefore, it is urgent to form a fast intelligent prediction method, especially with the development of large data processing and artificial intelligence methods.
This paper proposed a new method to predict water flooding performance using big data and artificial intelligence algorithms. The method regards layered reservoir as a vertical superposition of a series of single layer reservoirs. An injection-production analysis model is established in each single layer reservoir respectively. And then a superposition model is established only by production data and logging tools data. Finally, the least square principle and the particle swarm optimization algorithm are used to optimize the model and predict water flooding performance.
This method has been tested for different synthetic reservoir case studies. The results are in good agreement in comparison with the numerical simulation results. The average relative error is 4.59%, but the calculation time is only 1/10 of that of numerical simulation by using artificial intelligence method. It showed that this technique has capability to predict water flooding performance. These examples showed that the use of artificial intelligence method not only greatly shortens the working time, but also has a higher accuracy.
By this paper, it is possible to predict the water flooding performance easily and accurately in reservoirs. It has an important role in the field development, increasing or decreasing investment, drilling new wells and future injection schedule.
PDO Integrated Journey Management System IJMS
Authors: Hadzic Demir , Al Balushi Anwar 
Published: November 2019

Abstract
IJMS is PDO in-house developed solution made to support and enhance road safety in land transport operations. With more than 300 million kilometers driven per year in PDO, in harsh environment, driving is still the highest potential injury risk. IJMS has directly influenced the enhancement of road safety in PDO O&G operations. It became a role model for other O&G companies in Oman. The system enabled achieving 97% of drivers' compliance since its launch in January 2016. It supported PDO efforts in managing the risk in land transport, and to optimize its and contractors drivers' performance and behavior.
In the first chapter, the main theory and definitions were presented including road safety initiatives and best practice globally and in O&G industry that are related to IJMS.
Second chapter describes the system modules and their purposes. IJMS is modular system with integrated modules, which enables further development and enhancement of IJMS.
In the third chapter, main data and results achieved by using IJMS are presented and discussed. In addition, further actions for managing IJMS results are presented in this part.
Finally, the conclusion includes discussion about benefits and further plans of the system development.
A Novel Approach to Reduce Breakdown Pressure of Unconventional Rocks Using Cyclic Injection Scheme
Authors: Al-Nakhli Ayman , Tariq Zeeshan , Mahmoud Mohamed , Abdulraheem Abdulazeez , Al-Shehri Dhafer , Murtaza Mobeen 
Published: November 2019

Abstract
Recent rise in global warming and fluctuations in world economy needs the best engineering designs to extract hydrocarbons from unconventional resources. Unconventional resources mostly found in over-pressured and deep formations, where the host rock has very high strength and integrity. Fracturing techniques becomes very challenging when implemented in these types of rocks, and in many cases approached to the maximum operational limits without generating any fracture. This leaves a small operational window to initiate and place the hydraulic fractures. Current stimulation methods to fracture these formations involve with adverse environmental effects and high costs due to the entailment of water mixed with huge volumes of chemicals such as biocides, scale inhibitors, polymers, friction reducers, rheology modifiers, corrosion inhibitors, and many more.
In this study, a novel environmentally friendly approach to reduce the breakdown pressure of the unconventional rock is presented. The new approach makes it possible to fracture the high strength rocks more economically and in more environmentally friendly way. The new method incorporates the injection of chemical free fracturing fluid in a series of cycles with a progressive increase of pressure in every cycle. This will allow stress relaxation at the fracture tip and correspondingly enough time for fracturing fluid to infiltrate deep inside the rock sample and weaken the rock matrix. As a result of which the tensile strength-ultimately the breakdown pressure of the rock gets reduced. The present study is carried out on different cement blocks.
The post treatment experimental analysis confirmed the success of cyclic fracturing treatment. The results of this study showed that the newly formulated method of cyclic injection can reduce the breakdown pressure by up to 24% of the original value. This reduction in breakdown pressure helped to overcome the operational limits in the field and makes the fracturing operation greener.
Sensitivity Analysis and Decision Trees for the Identification of the Causes of Pressure Oscillations in Oil&Gas Production Systems
Authors: Borghi Riccardo , Bianco Amalia , Rizzo Cascio Joseph , Cadei Luca , Montini Marco , Zio Enrico , Baraldi Piero , Lu Xuefei 
Published: November 2019

Abstract
An Oil&Gas production system is based on the pressure balance between the reservoir and the delivery point. Since a deviation of the flowing conditions in a single point of the production system has consequences in the entire asset, a big challenge for flow assurance engineers is to preserve a stable pressure in the system, with a particular attention at the separator level.
Given that the description of pressure oscillations in the systems provided by the available simulators, based on first principle, is not always enough accurate and reliable as needed for practical applications, it is fundamental to develop models and tools to help plant operators in understanding the phenomenon and properly managing it. In this context, the objective of the present work is to use large datasets, containing historical measurements of hundreds of plant signals, for identifying the most critical components of the production system with respect to the pressure oscillation phenomenon and extracting knowledge from it.
To this aim, a novel indicator of the intensity of the pressure oscillation phenomenon in the separators has been firstly defined combining Discrete Short Time Fourier Transform and Principal Component Analysis. Then, a method to extract information on the causes of the oscillation phenomenon has been developed. It is based on (i) the prioritization of the plant signals importance with respect to the pressure oscillation by using the Maximum Information Coefficient and the moment-independent Kolmogorov-Smirnov distance; (ii) the aggregation of the signal for the identification of the most critical plant components; (iii) the extraction of rules describing the phenomenon by developing a Classification And Regression Tree model whose inputs are the most important signals in (i).
This method has been verified considering a production plant operated by Eni where the oscillations in the separator's pressure are frequent. The results show the effectiveness of the developed indicator of the intensity of oscillation and provide hints about the physical causes.
Advanced Loss Circulation Spacer System in UAE Enables Successful Cementation of 9 5/8" Casing and Required Zonal Isolation during Severe Losses
Authors: El Hassan Azza , Alaleeli Ahmed Rashed , Hamidzada Ahmedagha , Jose De Barros Adelson , Al Katheeri Yousif , Bin Tarsh Fatima , Aliyeva Gunay 
Published: November 2019

Abstract
It is common to be faced with severe losses prior to cementing the 9 5-8 in. intermediate casing in an offshore field in UAE. Intermediate casing covers weak zones and as a results there is always a high risk of formation breakdown and induced losses while running the casing and before it reaches intended setting point. The average losses experienced during drilling the 12 1-4 in. hole may exceed 100 BPH.
The main challenge in the case reviewed in this paper was that the formation was fracturing during casing running, compromising ability to achieve proper zonal isolation and successful cement job execution.
To address the challenge a special LCM Spacer system was proposed, designed to minimize or eliminate the losses during the primary cement job by offering superior sealing capabilities. This LCM Spacer system can easily mitigate loss circulation while cementing, based on ultra-low invasion technology forming a barrier across loss zones. It creates a film across formation walls and reduces the loss circulation ranging from partial to total losses on permeable, fragile, weak formation, natural fractures and depleted reservoirs. It also improves wellbore stability and ECD’s along the wellbore and expected loss zones.
The LCM Spacer system was designed and implemented based on the well conditions, design guidelines and previously recorded global success of the system applied in similar applications.