bluuebunny/crossref_metadata_2025_split huggingface dataset:
Enhanced oil recovery with carbon dioxide geosequestration: first steps at Pre-salt in Brazil
Authors: Godoi José Maria Alves , dos Santos Matai Patrícia Helena Lara 
Published: December 2021

AbstractThis paper revisits the intense using of energy in the world and the role of the fossil fuels with predominance of the oil in the global primary energy supply and their effects to climate change. It also presents a new reading on the thermodynamic conditions and characteristics of CO2 and CO2-EOR together with oil industry advancement in the world and Brazil. The interface with chemical EOR processes involving nanoparticles (NPs), their application inside the reservoirs for EOR and understanding of fines migration reducing, among other physical phenomena is also studied. Carbon capture and storage (CCS) is a worldwide strategy for mitigating climate change. CO2 geosequestration is also analyzed on the leakage of CO2 and brine from aquifers and their implication to the security of the storage and environment. Recent studies show that, globally, CO2-EOR can extract up to 375 billion of additional oil barrels and geological storage up to 360 Gt of CO2 in the next 50 years. Pre-salt is a complex of microbial carbonate reservoirs with stromatolite framework in ultra-deep waters (1500–3000) m depth, underneath by thick salt layer (2000–2500) m. Its reservoirs are in the depth up to (5500–6500) m TVDSS and approximately (200–300) km offshore. It presents light oils and high (GOR) ranging (200–400) Sm3/Sm3 and huge CO2 contamination (8–15)%. Due to the large CO2 content of oil, this work investigated CO2-EOR and CO2 geosequestration within the reservoirs. Pilot test demonstrated that miscible CO2-EOR with WAG is feasible and beneficial to this hydrocarbon Province. This study also calculated and validated the potential of CO2-EOR to the CCS. It concludes that Pre-salt can contribute to recovery factor (RF) increasing about 5.7 billion of additional oil barrels, and to CCS with about 266 Mt CO2 to be geological stored, for the next 20 years. In this context, this work also analyses the recent changes on the Brazilian oil and gas regulation to encourage new international Companies to enter in Brazil and Pre-salt for petroleum exploring. In Pre-salt, CO2-EOR also connects the petroleum energy system to CCS, transforming the oil reservoir in a carbon sink. These results represent a substantial role of Pre-salt to the energy efficiency of energy resources recovering from the biosphere and a high contribution to the climate change mitigation.
Productivity evaluation of horizontal well in heterogeneous reservoir with composite water aquifer
Authors: Yuan Hui , Li Wenhong , Yuan Yingzhong , Luo Jiao , Yan Wende 
Published: December 2021

AbstractHorizontal well is an important way to develop thin reservoir with edge-bottom water aquifer. For the horizontal well near oil–water contact, the reservoir have the features of edge water and bottom water at the same time. The productivity formula of horizontal well in pure edge water or pure bottom water reservoir is not fully applicable to this type of reservoir. For the heterogeneous reservoir with composite water aquifer, the horizontal well is divided into multiple well sections by using the concept of multi-segment well. Based on the seepage mechanics theory and potential superposition principle, considering the mutual interference between multi well sections, the productivity formula of horizontal well in heterogeneous reservoir with composite water aquifer is established. The new productivity formula considers the effect of reservoir heterogeneity, the quasi-linear flow of lateral edge water and the ellipsoidal flow of vertical bottom water. It can effectively determine the influence range and drainage distance of edge water in a heterogeneous reservoir with composite water aquifer. According to the test data of horizontal wells in Weizhou 11-1 oilfield, the drainage distancebof edge water is fitted and used to predict the productivity of new wells, and the result is very good. The research result lays a foundation for productivity prediction of horizontal well in heterogeneous reservoir with composite water aquifer.
Reservoir properties estimation from 3D seismic data in the Alose field using artificial intelligence
Authors: Ogbamikhumi A. , Ebeniro J. O. 
Published: December 2021

AbstractIn an attempt to reduce the errors and uncertainties associated with predicting reservoir properties for static modeling, seismic inversion was integrated with artificial neural network for improved porosity and water saturation prediction in the undrilled prospective area of the study field, where hydrocarbon presence had been confirmed. Two supervised neural network techniques (MLFN and PNN) were adopted in the feasibility study performed to predict reservoir properties, using P-impedance volumes generated from model-based inversion process as the major secondary constraint parameter. Results of the feasibility study for predicted porosity with PNN gave a better result than MLFN, when correlated with well porosity, with a correlation coefficient of 0.96 and 0.69, respectively. Validation of the prediction revealed a cross-validation correlation of 0.88 and 0.26, respectively, for both techniques, when a random transfer function derived from a given well is applied on other well locations. Prediction of water saturation using PNN also gave a better result than MLFN with correlation coefficient of 0.97 and 0.57 and cross-validation correlation coefficient of 0.89 and 0.3, respectively. Hence, PNN technique was adopted to predict both reservoir properties in the field. The porosity and water saturation predicted from seismic in the prospective area were 24–30% and 20–30%, respectively. This indicates the presence of good quality hydrocarbon bearing sand within the prospective region of the studied reservoir. As such, the results from the integrated techniques can be relied upon to predict and populate static models with very good representative subsurface reservoir properties for reserves estimation before and after drilling wells in the prospective zone of reservoirs.
Modeling research on the extreme hydraulic extension length of horizontal well: impact of formation properties, drilling bit and cutting parameters
Authors: Lu Nu , Zhang Bo , Wang Tao , Fu Qianming 
Published: December 2021

AbstractHorizontal well can increase well productivity and improve the economic benefit, which significantly promotes the development of shale gas, tight oil and heavy oil. Moreover, it plays an important role in the development of natural gas hydrate. Horizontal extension ability is one of the key indexes of horizontal well, but it is always impacted by formation properties and well structure. Therefore, a model is established to analyze the impact of formation properties and well structure as comprehensive as possible, which considers not only traditional influencing factors, like formation pressure and drilling bit parameters, but also other key factors, including cutting particle size, wellbore diameter and cross section. Based on the analysis, some advises are proposed for field application. The analysis indicates that horizontal well has stronger extension ability in the formation with low formation pressure and high fracture pressure, but it is still limited by pump pressure. Under-balanced drilling can strength the extension ability in high formation pressure by reducing drilling mud density. The natural fractures in formation should be noted when drilling long horizontal well. The extension length increases and then decreases with the cutting particle size, so cutting particle has optimal size for the horizontal extension length, which can be adjusted by the rate of penetration and rotation speed. The extension length increases first and then decreases with the gap between drilling string and hole. Considering the demand of rock breaking and cutting sweeping around drilling bit, it is not recommended to adjust the drilling bit parameters. Both the cutting bed height and drilling string eccentricity have impact on horizontal extension length by changing minimum cutting-carry pump rate and annular pressure drop. Under different combinations of above two parameters, minimum cutting-carry pump rate and horizontal extension length are determined by different factors and can be divided into three parts, including acceptable cutting bed height, cutting lifting efficiency, pump pressure and total circulation pressure loss and well bottom pressure and formation fracture pressure. The findings of this study can help for better understanding of horizontal well hydraulic extension length and optimization method.
Geophysical appraisal for the sandy levels within Abu Roash C and E members in Abu Gharadig Field, Western Desert, Egypt
Authors: Sarhan Mohammad Abdelfattah 
Published: December 2021

AbstractThe present work concerns with the geophysical assessment for the sandstones of Abu Roash C and E members for being potential hydrocarbon reservoirs at Abu Gharadig Field, Western Desert, Egypt. The analysis of seismic data covers Abu Gharadig Field showing ENE–WSW anticline fragmented by NW–SE normal faults. The presence of these structures is due to the dextral wrench corridor that extensively deformed the north area of the Western Desert within Late Cretaceous episode. The examination of well-log data of Abu Gharadig-6 Well revealed that the favourable zone locates between depths 9665–9700 ft (zone I) within Abu Roash “C” Member. The second promising zone in Abu Gharadig-15 Well occurs between depths 9962–9973 ft (zone II) in Abu Roash “E” Member. The quantitative evaluation indicated that zone I has better reservoir quality than zone II since it is characterised by low shale volume (0.01), high effective porosity (0.22), low water saturation (0.14), low bulk volume of water (0.03), higher values of absolute permeability (113 mD), high relative permeability to oil and low water cut, whereas zone II has 0.13 shale volume, 0.16 effective porosity, 0.39 water saturation, 0.06 bulk volume of water, lower values of absolute permeability (27 mD), low relative permeability to oil and relatively high water cut. The obtained results recommended that the drilling efforts should be focused on the sandy levels within Abu Roash C Member (1st priority) and the sand levels within Abu Roash E Member (2nd priority) in Abu Gharadig Basin and its surroundings.
Evaluation of reservoir performance by waterflooding: case based on Lanea oilfield, Chad
Authors: Zene Mahamat Tahir Abdramane Mahamat , Hasan Nurul , Jiang Ruizhong , Zhenliang Guan , Abdullah Nurafiqah 
Published: December 2021

AbstractThe research of the current study is primarily focused on evaluating the reservoir performance by utilizing waterflood technique, based on a case study at Lanea oil field located in Chad; various mechanisms along with approaches were used in considering the best suitable pattern for waterflooding. All the simulation work was compared against a base case, where there was no involvement of water injection. Moreover, for the base case, a significant amount of oil left behind and cannot be swept, because of lower reservoir pressure at the downhill. The recovery factor obtained was in the range of 14.5–15% since 2010, and in order to enhance the oil production, an injection well was applied to boost the reservoir pressure; oil recovery is improved. In addition, sensitivity analysis study was performed to reach the optimum production behavior achieved by possible EOR method. Parameters, such as grid test, injection position, proper selection production location, permeability, and voidage substitution, were defined in the simulation study.
Enhanced oil recovery application in low permeability formations by the injections of CO2, N2 and CO2/N2 mixture gases
Authors: Bougre E. S. , Gamadi T. D. 
Published: December 2021

AbstractLow oil recovery which is very predominant in shale oil reservoirs has stimulated petroleum engineers to investigate the applications of enhanced oil recovery methods in these formations. One such application is the injection of gases into the formation to stimulate increased oil recovery. In many gas flooding projects performed in the field, the miscibility of the gas injected is usually the most desired displacement mechanism, and carbon dioxide (CO2) gas has been recognized to be the best performing gas for injection due to its ability to be miscible with oil in the reservoir at low pressures compared to other gases such as nitrogen. This minimum miscibility pressure (MMP) is of very crucial importance because it is the primary limiting factor in the feasibility of a miscible gas flooding project. However, there are other limiting factors such as cost and availability and, in these instances, nitrogen (N2) and lean gas are the more preferred candidate as opposed to carbon dioxide gas. Mixing carbon dioxide gas with lean gas or with nitrogen in a required ratio can allow us to design an injection gas that will be suitable enough to satisfy both the availability and cost constraints and at the same time allow us to achieve a reachable and reasonable miscibility pressure. The objective of this paper is to investigate the effect of mixing nitrogen gas and carbon dioxide gas in a 50:50 ratio on oil recovery in tight oil formations. The experiment was performed with controlled constraints such as the same core sample, same crude oil and same core cleaning and saturation process which was repeated for each trial. The oil used was live oil from Eagle ford formation, and the gases used were nitrogen (99.9% purity), carbon dioxide and a mixture of nitrogen and carbon dioxide in a 50:50 ratio. The injection pressure ranged from 1000 to 5000 psi with pressure increments of 1000 psi, and the same flooding time was 6 h. The potential of the N2, CO2 and N2–CO2 mixture for improving oil recovery was assessed along with the breakthrough time. The results showed that CO2 gas had the highest recovery followed by the N2–CO2 mixture and N2 gas had the lowest recovery. The gas breakthrough time results showed that the N2–CO2 mixture had the longest breakthrough time, N2 had the shortest breakthrough time, and CO2 had a significantly longer breakthrough time than pure N2 gas. The RF increased with increasing pressure, but the gas breakthrough time decreased with increasing pressure. However, the incremental RF decreased in all three cases when the injection pressure was above 3000 psi.
Characteristics of increasing displacement efficiency by surface-active polymer flooding for enhancing oil recovery
Authors: Yu Qiannan , Liu Yikun , Liang Shuang , Tan Shuai , Chen Chenghan , Sun Zhi , Yu Yang 
Published: December 2021

AbstractSurface-active polymer is a novel multifunctional active polymer applied for enhancing oil recovery which has both viscosity-increasing ability and surface activity. Experiments were carried out to indicate basic physicochemical properties of surface-active polymer and to study on differences of properties between surface-active polymer and other chemical flooding agents, and characteristics of increasing displacement efficiency by surface-active polymer flooding have been tested. Experimental results show that the molecular aggregation conformation, viscosity performance and flow capacity of surface-active polymer were significantly different from those of other chemical flooding agents. Positive effects of viscosity and viscoelastic properties and improvements in interfacial chemical properties are basic characteristics of increasing displacement efficiency by surface-active polymer flooding which are basic principles of surface-active polymer flooding for enhancing oil recovery.
Geo-electrical investigation of the groundwater potential of Ogidi and environs, Anambra State, South-eastern Nigeria
Authors: Onyekwelu C. C. , Onwubuariri C. N. , Mgbeojedo T. I. , Al-Naimi L. S. , Ijeh B. I. , Agoha C. C. 
Published: December 2021

AbstractThe electrical resistivity method was used to determine the groundwater potential of Ogidi and its environs. Thirteen soundings were carried out at thirteen different locations using the ABEM terrameter (SAS 1000), and adopting the Schlumberger configuration with maximum current electrode spacing of 1000 m. The lithologic logs for the boreholes were used to delineate the geologic sections. The results revealed six to nine geo-electric layers comprising laterite, clayey sandstone, sandstone, water-saturated sandstone and shale. The water-saturated sandstone forms the aquiferous unit. This unit was found to have resistivity values ranging from 363Ωm to 9107Ωm. It is deeply seated in some areas with a depth of 33.2–103 m. It was observed that the hydraulic conductivity varies between 0.001 and 0.066 m/day, while the transmissivity values vary between 0.01 and 4.7 m2/day. Among all the VES points studied, it was observed that VES 1 has the highest transmissivity value and the highest aquifer thickness. In view of the foregoing, it is expected that water will flow more from aquifer in VES 1 since groundwater flow from an aquifer is directly proportional to transmissivity.
Application of particle swarm optimization and genetic algorithm for optimization of a southern Iranian oilfield
Authors: Razghandi Milad , Dehghan Aliakbar , Yousefzadeh Reza 
Published: December 2021

AbstractOptimization of the placement and operational conditions of oil wells plays an important role in the development of the oilfields. Several automatic optimization algorithms have been used by different authors in recent years. However, different optimizers give different results depending on the nature of the problem. In the current study, a comparison between the genetic algorithm and particle swarm optimization algorithms was made to optimize the operational conditions of the injection and production wells and also to optimize the location of the injection wells in a southern Iranian oilfield. The current study was carried out with the principal purpose of evaluating and comparing the performance of the two most used optimization algorithms for field development optimization on real-field data. Also, a comparison was made between the results of sequential and simultaneous optimization of the decision variables. Net present value of the project was used as the objective function, and the two algorithms were compared in terms of the profitability incremental added to the project over twelve years. First, the production rate of the producers was optimized, and then water alternating gas injection wells were added to the field at locations determined by engineering judgment. Afterward, the location, injection rate, and water alternating gas ratio of the injectors were optimized sequentially using the two algorithms. Next, the production rate of the producers was optimized again. Finally, a simultaneous optimization was done in two manners to evaluate its effect on the optimization results: simultaneous optimization of the last two steps and simultaneous optimization of all decision variables. Results showed the positive effect of the algorithms on the profitability of the project and superiority of the particle swarm optimization over the genetic algorithm at every stage. Also, simultaneous optimization was beneficial at finiding better results compared to sequential optimization approach. In the end, a sensitivity analysis was made to specify the most influencing decision variable on the project’s profitability.
The novel technology for reservoir stimulation: in situ generation of carbon dioxide for the residual oil recovery
Authors: Panahov Geylani M. , Abbasov Eldar M. , Jiang Renqi 
Published: December 2021

AbstractThe gas and chemical flooding for reservoir stimulation with residual hydrocarbons reserves are highly relevant problem of current oil and gas recovery strategy. The objective of this paper is laboratory study and field implementation of new gas-EOR technology—in situ carbon dioxide generation technique for CO2-liquid slug formation under oil displacement, increasing the reservoir sweep efficiency and residual oil recovery. This paper presents a summary of a wide range of laboratory tests conducted on different core samples and chemical compositions. Several physical and hydrodynamic phenomena of in situ CO2generation in highly permeable zones of a porous medium have been investigated as a part of complex study, which involved laboratory tests on the field-scale industrial technology applications, determination of optimal concentrations of foaming agents and inhibiting additives in gas-releasing solutions, etc. The results of laboratory experiments showed that the incremental recovery ranged between 30 and 35% oil original in place. The unique results of the field implementation provide developing an optimal technological scheme of reservoir stimulation with residual oil reserves both onshore and offshore oil fields. Technology of in situ CO2generation was applied on the group of wells on Penglai offshore oil field (Bohai Bay). Incremental oil production for field operation was 37,740 bbl of crude oil. Theoretical and laboratory studies, as well as the outcomes of industrial implementation of a new method of residual oil recovery, using a CO2-slug confirm technology and economic profitability of the proposed solution.
Experimental investigation of proppant clustering in intersected fractures
Authors: Ma Wenpei , Tomac Ingrid 
Published: December 2021

AbstractThis paper investigates the dynamics of proppant agglomerations during flow and transport within fractures intersected at the angles typical for the joint of pre-existing and newly formed fractures. The study considers variations and coupling of fluid flow rates, proppant volumetric concentrations, fluid dynamic viscosities and fracture intersection angles. Proppants are widely used during hydraulic fracturing to keep fractures open and enhance reservoir permeability. This study uses plexiglas experimental slots and visual analysis for identifying particle displacements. Geo-Particle Image Velocimetry–Reliability-Guided (GeoPIV-RG) method tracks particle movements among images by comparing the reference and subsequent snapshots at the point and time of interest. Results of this study show that the proppant volumetric concentration and the fluid flow rate are closely correlated with each other for affecting proppant flow, transport, and agglomeration formation. Increasing the proppant volumetric concentration generally promotes particle agglomeration, with different extent when coupled with the fluid flow rate. Proppant volumetric concentration affects the size, shape, and distribution of particle clusters. Increasing the fluid flow rate increases the occurrence of particle agglomerates at low proppant volumetric concentration; however, this trend is absent under high proppant volumetric concentrations. Sizes and shapes of proppant agglomerates change as the fluid flow rate changes. Changes of fracture intersection angle minimally affect shape, size and distance between proppant agglomerates and clusters. Furthermore, increasing the fluid dynamic viscosity strongly promotes proppant agglomeration. Although fluid dynamic viscosity changes do not affect the shape and size of particle clusters, the distance between adjacent clusters decreases at higher fluid dynamic viscosity.