bluuebunny/crossref_metadata_2025_split huggingface dataset:
CLONNE Modeling, A Novel Core and Log Prediction Through Artificial Neural Network
Authors: C A Razak M Amin , Khalid Khaliza , Sutiyono Sigit , M Shah Jamari , Md Zainuri Md Zarin 
Published: November 2019

Abstract
Core & Log Neural Network Modeling (CLONNE) has been initiated to utilize an ANN to optimize usage of available data to generate synthetic logs and core data which enable user to eliminate any special logs and core data acquisition in the future. This will reduce the well cost and time required for data acquisition and data analysis.
CLONNE process starts with data gathering of the available core and log data which then QC'ed and conditioned for bad hole, light hydrocarbon, thin lamination and normalized. Then pair of core and log data are combined as dummy well to generate the first CLONNE model that can be used to predict for the whole fields. Conventional data including density, neutron, sonic, GR logs and other parameters are used to generate output. A random well from the field is selected to test the predictability matching of CLONNE versus the real data acquired. Several calibration performed to provide the best predictability.
Currently a number of CLONNE models have been created for offshore fields in Malaysia. For CLONNE Synthetic logs, 4 models have been created to predict Porosity, Bulk Density, Neutron and Shear Slowness. For CLONNE Synthetic core, 3 models have been created to predict Grain Size, Permeability and Porosity. All of this models have managed to predict quite well in both thick sand and laminated sand. More models will come to predict other log curves and core parameters. The models established has been tested in one field, where a synthetic sonic log has been created. After the drilling and subsequent logging run, an actual sonic log has been deployed and compared which yield to 96% comparable. The data predicted from CLONNE can greatly save almost 15 months spend to acquire and analyze core data and also almost RM 6 Million total expenditure to acquire and analyze core data.
In 2018, CLONNE has achieved RM 6 Million cost avoidance from application in 3 fields in Malaysia. The CLONNE model generated can be implement to Basin wide prediction thus enable the sharing use of data. This will help to integrate the data available instead of data being utilize in the specific field only.
Reservoir Inter-Well Connectivity Analysis Based on a Data Driven Method
Authors: Liu Wei , Liu Wei David , Gu Jianwei 
Published: November 2019

Abstract
Quantitative study of inter-well connectivity is significant for understanding which injector influence the producer, and making rational injection operations to improve water flooding efficiency. In this paper, a data driven method is presented to evaluate inter-well connectivity based on bottom-hole pressure of both injection wells and production wells.
In the development and production of fields, producers are always kept in constant production rate. Thus it is more appropriate to conduct inter-well connectivity analysis using bottom-hole pressure data rather than historical injection and production rates. However, the bottom-hole pressure data cannot directly obtained. The on-site monitored well head pressure and dynamic liquid level are first used to computation and obtain bottom-hole pressure for both injectors and producers. And then preprocessing the bottom-hole pressure using non-linear diffusion filters for capturing attenuation and time lag, and constituted the data set for machine learning. An artificial neural network (ANN) is then generated and trained to simulate connect relations between producers and its surrounding injectors. Genetic algorithm (GA) is also applied to optimize the time lag and hyper parameters of ANN, which helps to save time compared to subjective adjustments. In the last, sensitivity analysis is conducted on the well-trained ANN to quantify connectivity between injectors and producers, and detecting the connect status.
The proposed methodologies were first applied to two synthetic case, and then to real field case. The results were shown to be capable of capturing connection relations between injectors and producers, and highly consistent with known geological features, analyze results and tracer test of reservoir engineers. It indicates that the presented methods can be used to understand the flow direction of injected water, and guide to optimize water injection operation.
Treatment of Produced Water with Back Produced ASP
Authors: Al Battashi Mundhir , Al Shukaili Saada , Al Balushi Sa'ud , Al Hatmi Khalid , Al Mashrafi As'ad 
Published: November 2019

Abstract
Crude oil production from ageing oil fields is normally sustained by various enhanced oil recovery (EOR) ways such as water injection, polymer injection and alkaline surfactant polymer injection (ASP). One of the main ageing fields (90% water cut) in Oman is considered for this study. This field is being operated with waterflood for more than 15 years. In order to enhance the oil recovery in this field, chemical enhanced oil recovery (cEOR) using polymer flood was implemented in 2010 by Petroleum Development Oman (PDO) Company. ASP is a recovery method planned as a final resort of cEOR to recover more oil from the studied field. ASP breakthrough is expected to impact the performance of deoiling facilities in this field.
Results showed that using ceramic membrane (100 nm pore size) managed to remove oil from produced water completely for high and low OiW concentrations, however only 2% recovery factor was achieved. Using aluminum sulfate chemical as a coagulant to treat the oily produced water was only effective at concentration higher 500 mg/L. In comparison, aluminum sulfate was very effective in treating the produced water contaminated by polymer (500 ppm of polymer concentration) and at 150 mg/L of aluminum sulfate, the outlet OiW reached 39 ppm (v). When Aluminum sulfate was used at concentration of 500 mg/l, the OiW concentration reached 2 ppm (v), which is lower than the polishing unit in the water treatment system. When ASP was introduced to the produced water, the oil droplet stability has increased and at 500 mg/L of aluminum sulfate, the outlet OiW in the treated stream was around 65 ppm (v) however at 700 mg/L of aluminum sulfate, zero ppm of OiW was achieved. Introducing gas bubbles (N2) as flotation with the help of the coagulant agent had improved OiW removal efficiency by almost 15% for the PW with ASP.
A Method of Intelligent Scheme Optimization for Non-Stop System Intermittent Production Units
Authors: Wang Cai , Xiong Chunming , Shi Junfeng , Han Qiqing , Zhang Jianjun , Zhao Ruidong , Lei Gang , Zhang Xishun , Sun Yizhen 
Published: November 2019

Abstract
Long-time and over-frequency system power-off of normal intermittent pumping (NIP) technology may exacerbate wax deposit, hydrodynamic level instability and even system restart failure. As a consequence, non-stop-system intermittent pumping (NSSIP) have been tentatively applied into some wells of low production in the oilfield of Daqing in China. Long time pump stop will reduce well production while frequent pumping will lead to void pumping and high energy consumption. Now, NSSIP production scheme is mostly derived from experience decision, the feed and fetch of pump is unbalanced, and it is doubtful whether the low energy consumption characteristic of NSSIP really works. Thus, it is urgent to carry on the research of intelligent scheme optimization for NSSIP.
First, based on the A5 database platform of CNPC, the deliberate non-stop pumping scheme and data acquisition scheme for typical experimental wells will be formulated. Second, data of load, displacement and production rate of pumping wells by NSSIP will be measured in real time, then the pump efficiency vs dynamometer working condition will be calibrated accordingly. The CNN+SNN+HDG model is used for training, and the quantitative diagnosis model of insufficient liquid supply is established to realize the intelligent prediction of pump efficiency through dynamometer recognition. Third, the physical model of bottom hole flowing pressure buildup is established to realize the quantitative evaluation of reservoir liquid supply capacity. Data models for correlation analysis of the pumping time, dynamic liquid level, output rate, system efficiency and other parameters are established. At last, the key parameters that affect the pump balance of feed and fetch and economic benefit of a single well are screened out, and the all above analysis results and models are integrated into the ensemble decision tree model to optimize the most reasonable pumping time and frequency for NSSIP schemes.
It is suggested that fluid supply capacity affect the intermittent scheme most. For low permeability and low production well, NSSIP could sustain pump fullness, increase system efficiency and save energy at the same time. Based on the ensemble method for intelligently production scheme optimization, NSSIP could increase system efficiency by 7.8% over normal pumping, and by 4.4% over normal intermittent pumping in average. What's more, NSSIP could reduce energy consumption by 22.14 kWh per day compared with intermittent in average.
Non-stop-system intermittent pumping (NSSIP) may effectively prevent pumping system from failures caused by void pumping or long-time system stop. It could also greatly increase pumping and system efficiency and save more energy.
Using Shear Wave Anisotropy Approach to Determine State of Stress Around the Wellbore from Advanced Acoustic Well Logging; Case Study from Southern Iraq
Authors: Dahm Haider H. , Abbas Ahmed K. , Alhumairi Mohammed A. , Alsaba Mortadha , Mohammed Haider Q. , Al-Hamad Nasser 
Published: November 2019

Abstract
Drilling operations in deep shales are more challenging due to geomechanical problems such as wellbore instability. Neglecting the impact of geomechanical issues may lead to drilling drawbacks such as loss of circulation, wellbore collapse, tight hole while tripping, stuck logging tools, and subsequent fishing, stuck pipe, and sidetracking. The directional dependency (anisotropy) of the rock properties, especially the rock strength, cause variation in the wave velocities. Identifying orientation and degree of the anisotropy and its relationship with geomechanical problems is essential for further field development. In this paper, acoustic data from vertical and deviated wells in Zubair Formation, Southern Iraq were performed to provide insights on the state of stress distribution around the wellbore through the Zubair Formation. In addition, interpreting the flexural dispersion curves as the final result of cross-dipole data processing, the maximum stress direction has been obtained to illustrate the type and source of anisotropy around the borehole in this formation. Using the flexural dispersion curves and the shear wave splitting approaches, the direction and the degree of anisotropy were determined in Zubair formation. Results indicated that drilling operations have altered the state of stress around the wellbore, and the degree of alteration is a function of the magnitude and the direction of the anisotropy. The flexural dispersion curve shows that the upper member of Zubair Formation is strongly anisotropic, whereas a slight anisotropy was mapped within the middle member of the same formation. In addition, shear wave splitting analysis revealed that the stress changes along the direction striking from north to west. Thus, considerable attention should be paid to all 1D-geomechanicsl models that constructed for Zubair Formation given its strong aviation of the magnitude and direction of its strength and elastic properties.
Innovative Pioneer Approach for Gas Wells Testing without Flaring in Offshore Field Abu Dhabi
Authors: Ladmia Abdelhak , Al Hammadi Yousif Hasan , Al Hosani Fahad Mustfa , Ballaith Faisal Jamaan , Alshamsi Abdalla Hussain , Hussein Ahmed , Essam Ahmed 
Published: November 2019

Abstract
Technical difficulties to test and monitor Offshore Gas wells completed with 7" mono-bore (High rates: 100-120 MMSCFD & Barge Testing equipment are limited to a Max. rates of 45 MMSCFD or less) and the impact of shutting these wells on the gas deliver.
An innovative solution that is industrially and ecologically superior to more traditional methods of gas testing. The SONAR technology of the Clamp on SONAR Flow Surveillance provides accurate measurements of gas flow rate with no pressure drop or energy loss, a wide turn-down ratio and no need to cut the pipe or stop the flow, installation is easy and maintenance is minimal. The combination of accurate measurements and ease in installation makes the Clamp on SONAR Flow Surveillance the perfect fit for a very wide range of applications. It provides the optimum basis for solutions that are perfectly tailored to Offshore Gas wells.
Clamp on SONAR flow surveillance is particularly flexible and economical, reduce engineering time, increase plant availability and enable practice- related well production. Test at any time Gas wells & detects any change. This is critical for most Offshore Gas wells reservoir development projects.Remove Barge testing; avoid associated problems & saving Barge timeSafe, Quick & InexpensivePrevent production cut off & loss while conducting testingGood saving in term of Barge Cost and Gas Gain.
By applying the SONAR technology of the Clamp on SONAR Flow Surveillance that provides accurate measurements of gas flow rate with no pressure drop or energy loss, a wide turn-down ratio and no need to cut the pipe or stop the flow, in addition to the easy installation where the maintenance is minimal as well as to save significant cost of the Barge and gas flaring.
An example of a novel technical concept and serves as a motive for applying new technology to test High Rate Gas wells that can assure safe continuous monitoring in addition to save Barge Time & Cost and Prevent production cut off & loss.
Managing High Cost in Offshore Construction : Pan Malaysia Maintenance, Construction and Modification PM-MCM Strategic Initiative
Authors: Zakaria Irman Zubir , Engku Mahmud Engku Azam , Md Farick Farahin , Juhari Muhammad , M Johari Arina 
Published: November 2019

Abstract
Pan Malaysia Maintenance, Construction and Modification (PM-MCM) Contract 2018 – 2023 is a PETRONAS-led initiative in collaboration with Malaysian Oil & Gas Operators, which are also known as Petroleum Arrangement Contractors (PAC), aimed at cost optimization through the technical standardization of offshore Hook-up and Commissioning (HUC) and Topsides Major Maintenance (TMM) works. The initiative was participated by ten (10) Petroleum Arrangement Contractors (PACs) operating in Malaysia (redundant).
The initiative competitiveness relied heavily on the number participating PACs in order to accumulate and integrate sufficient volume of work through sharing of their long-term offshore work plan over a period of 5 years with active contribution on lessons learned, best practices, and challenges. Leveraging on high volume of work per region will generate the economics of scale thus drive cost reduction.
The technical standardization is achieved through the identification of minimum requirements for each work (HUC and TMM) by operators, and where applicable, common specifications are accordingly derived. This simplifies the requirements and accordingly reduces the number of specifications to be complied across the region, thus, effectively allows the HUC/TMM Contractors to competitively quote the best price for the services.
Apart from the technical standardization and optimization above, the initiative is further supplemented through the standardization of the Contract Terms and Conditions among the PACs. However, landing to an agreement amongst the ten (10) established Oil & Gas Companies was crucial and considered as a major challenge, as each company had operated differently under their own set of Terms & Conditions. Despite this, consensus achieved towards standardization.
In assisting the tender evaluation and aligning with PETRONAS’ effort towards Digitalization of its Busines Operation, digital tools were deployed. Online eAuction and digital bid price analyzer were extensively used to commercially evaluate and to identify best value for PETRONAS and PACs, respectively.
In conclusion, the PM-MCM contract was successfully awarded with a significant cost reduction against the original estimated cost by approximately 40%. In comparison to previous contracts, Pan Malaysia MCM also recorded significant reduction in most of the unit rates of similar services rendered. Market feedbacks obtained by participating bidderss indicated that the standardization had indeed helped the participants to lower their prices.
Pan Malaysia Maintenance, Construction and Modification Contract has brought forward industry players into one crucial objective of cost optimization. The collaboration between PETRONAS and PAC which resulting for greater impact and value to all players involved through productivity improvement and cost reduction.
Effect of CuO and ZnO Nanoparticles on Efficacy of Poly 4-Styrenesulfonic Acid-Co-Maleic Acid Sodium Salt for Controlling HPHT Filtration
Authors: Beg Mukarram , Kesarwani Himanshu , Sharma Shivanjali 
Published: November 2019

Abstract
Water based muds (WBM) provide an eco-friendly and cost effective way out for drilling a petroleum well without using oil based muds. WBM may cause some problems when a water sensitive formation (such as shale) is encountered during drilling. The infiltration of water from mud causes formation minerals to dissolve that may lead to formation damage. Fluid loss also alters the rheological properties of mud which is highly undesirable hence fluid loss should be minimum.
Present study aims to experimentally investigate the effect of CuO and ZnO nanoparticles in presence of poly(4-styrenesulfonic acid-co-maleic acid) sodium salt (PSSM) as a fluid loss control agent for WBM at high pressure-high temperature (HPHT) conditions. Base mud containing hydroxyethyl cellulose was mixed with 1.0 w/v% of PSSM and varying concentrations of either nanoparticle (0.25, 0.50, 0.75 and 1.00 w/v%). The resulting drilling fluid formulations were examined by using viscometer, high temperature ageing cell in roller oven, API filter press, HPHT filter press and capillary suction timer. Zeta potential of nanoparticles in water with and without PSSM was measured using particle size analyser. Filter cake formed by API filtration tests were analysed by field emission scanning electron microscope (FESEM). Ageing experiments were also performed at 230°F for 16 hours and HPHT filtration tests were conducted at 300°F.
Experimental studies have shown that the addition of CuO decreased the rheological parameters such as apparent viscosity, plastic viscosity and yield point by 10 to 15% before hot rolling of drilling fluid. After hot rolling, the rheological parameter for mud containing CuO were reduced, but as the concentration of nanoparticle increased, the rheological properties improved. Effect of CuO was more pronounced as compared to ZnO nanoparticles on fluid loss. The addition of 1.0 w/v% PSSM in base mud reduced LPLT fluid loss to ~64%. API fluid loss of PSSM containing mud was further reduced by ~12% on addition of only 1.0 w/v% of CuO. At 1.0 w/v% concentration of ZnO, API filtrate of base mud reduced by ~8%. HPHT filtrate loss for mud having 1.0 w/v% PSSM was 14.6 mL in 30 minutes at 300°F. Addition of nanoparticles further reduced HPHT filtration loss by 15 to 20%. FESEM images of filter cakes suggested that there were complex structures of polymer chains covering the pores of filter cake, and the network was further blocked by the nanoparticle clusters, therefore inhibiting the passage of fluid through it.
The results obtained from this experimental work have shown that the efficiency of polymer as fluid loss reducer has improved due to the addition of nanoparticles, especially with CuO. The novel combination of CuO nanoparticles with poly(4-styrenesulfonic acid-co-maleic acid) sodium salt can further be explored and engineered to develop an efficient fluid loss reducing formulation for water based mud.
A Microfluidic Study of Wettability Alteration Rate on Enhanced Oil Recovery in Oil-Wet Porous Media
Authors: Yuan Shuai , Liang Tianbo , Zhou Fujian , Liang Xingyuan , Yu Fuwei , Li Junjian 
Published: November 2019

Abstract
Replacing oil from small pores of tight rocks relies on altering the rock wettability with the injected fracturing fluid. Among different types of wettability-alteration surfactants, liquid nanofluid (LNF) has less adsorption loss during transport in the porous media and can efficiently alter the rock wettability; both make LNF a promising candidate to enhance oil recovery from tight reservoirs. In this study, a 2.5-D visualized micromodel with micro-sized pore throats is applied to elucidate the impacts of wettability alteration and spontaneous imbibition on oil-water flow in the porous media. Results provide direct evidence that the concentration of LNF changes wettability alteration rate and interfacial tension, and thus influencing the displacing rate of water into the originally oil-wet pores. This helps to optimize LNF usage in the fracturing fluid for enhanced oil recovery from tight rocks.
Reservoir Modeling using Thin Layer Analysis and Characterization e-tlac™ Approach for Turbiditic Environment
Authors: Gangemi Giovanni , Galli Maria Teresa , Cruciani Francesco , Barbacini Giulia , Dallorto Margherita 
Published: November 2019

Abstract
Thin turbidity siliciclastic reservoir is a challenging deep-water environment for modeling. In a deep off-shore field in West Africa, sedimentological characterization of these reservoir suggests typical turbiditic sandstones: Arenites with medium granulometry and normal gradation over imposed by plane-parallel sand laminations intercalated by shaly levels (late stage turbidity sandstone beds - characterization by Mutti, 1992). The oil bearing reservoir, is producing both from thick sands and thin layer sands. It is supposed the presence of up to 40% of sand-shale inter-bedded layers with a thickness less than 0.3m.
These sands are defined in the reservoir model by curves of petrophysical properties, log facies, characterization of thin bedded intervals and a volume of seismic inversion.
Tuning analysis suggest the potential seismic resolution is 16 meters. Seismic inversion was processed to generate a higher resolution driver for modelling.
Formation evaluation uses high-resolution logs within "Thin Layer Analysis and Characterization" (e-tlac™) method (Galli et Al., 2002) which helps enhancing thin inter-bedded facies characterization, not captured with conventional logs. The method provides an estimate of the Sand content, Porosity and Saturation logged by the tools with thin lithology.
High-resolution logs were acquired only in three wells over twelve drilled in the field. For this reason, a re-calibration of all conventional CPIs including the "e-tlac" output results was necessary to better control the reservoir property distribution all over the grid.
This methodology increased capability estimating pay volume close to real value avoiding underestimation of Net Sand and Water Saturation overestimation.
The solution to model thin turbiditic sands within the static 3D model is integrating all the above data inputs (stratigraphical environment, seismic inversion volume and "e-tlac" output). Reservoir cores was the input for the sedimentological study; the seismic inversion volume was background for reservoir facies distribution and "e-tlac™" formation evaluation output to assign unbiased reservoir properties to sand and thin layer facies at the well position.
As lesson learned, the acquisition of triaxial induction, high-resolution dielectric or image is the key to better characterize the inter-bedded thin levels that are present in similar deep-water environment.