Day 2 Tue, August 06, 2019最新文献

{"title":"Investigation of Sediment Migration From The Abakaliki Anticlinorium To The Anambra Basin - A Geostatistical Approach","authors":"M. E. Okiotor, G. Asuen","doi":"10.2118/198774-MS","DOIUrl":"https://doi.org/10.2118/198774-MS","url":null,"abstract":"\u0000 The present investigation focused on geochemical evaluation of shale sequences in The Lower Benue Trough using geostatistical approach Thirty two representative samples of shale sequences of The Asu River Group, Nkporo Group and Mamu Formation in The Lower Benue Trough were subjected to Multi-Parameter study in an attempt to present a model of the sediment provenance, and paleoenvironment diagenetic conditions.\u0000 The X-ray diffraction and Inductively Coupled Plasma Mass spectrometry (ICP-MS) techniques were employed to examine and establish qualitative and quantitative constituents of the Major oxides, Trace and Rare Earth elements. The major minerals determined include SiO2 (40.96%, 56.08% & 60.39%)2, Al2O3 (15.09%, 18.27% and 21.16%), TiO2 (0.75%, 1.73% and 1.63%) and Fe2O3 (9.66%, 2.78% & 2.85%), for Asu River Group, Nkporo Group and Mamu Formation respectively. The studies suggest high influx of sediments into both The Abakaliki Anticlinorium and the Anambra Basin. When tested with multivariate statistical techniques such as Factor, Principal Component, Correspondence and Cluster analyses, the hidden affinities within the sediments were revealed in terms of similarities and dissimilarities. Enrichment and depletion of biogenic indicators CaO (EF=1.87 − 0.01) and P2O5 (EF=1.58 − 0.33) in the studied Asu River Group and Anambra basin sediments indicate deep marine to marginal marine paleoevironment of deposition respectively. Chemical examination of the maturity indexes indicate that the Anambra basin sediments were more matured, indicating that most of the Anambra Basin sediments were reworked from the Abakaliki Anticlinorium.","PeriodicalId":11110,"journal":{"name":"Day 2 Tue, August 06, 2019","volume":"104 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-08-05","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"75647050","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Successful Coiled Tubing Catenary Cement Packer and SAS Installation in a Horizontal Well for Developing Bypassed Reserves: Offshore Niger Delta","authors":"Yan Songa, Henry Ude, C. Uzodinma, C. Enyioko, E. Ighavini, O. Haruna, Godian Ndukauba","doi":"10.2118/198824-MS","DOIUrl":"https://doi.org/10.2118/198824-MS","url":null,"abstract":"\u0000 Rigless coiled tubing (CT) operations with CT operated from a floating anchored vessel are deployed for well intervention operations where crane limitations and deck loading constraint present multiple challenges for accessing the marginal/bypassed pay in offshore locations. This operation involves operating the CT unit with the reel located on the floating vessel and the injector head positioned on the offshore platform. The CT catenary design was successfully deployed for developing behind casing reserves through efficient zonal isolation, cement packer installation, perforations, and sand control.\u0000 This paper presents the use of 1.75-in. CT on a 125K unit catenary system in a highly deviated horizontal well (>85°) to develop the shallower reservoir. The well is located on a platform with insufficient deck space and load bearing capacity to accommodate the intervention spread. The through-tubing CT operations involve installation of mechanical isolation plugs, cement retainer (CR)/stinger; tubing punch, cement packer installation, perforation, and stand-alone-screen (SAS) installation. The depleted reservoir interval presents challenges with declining production amidst gas lift support and intermittent production attributed to liquid loading. 152 bbl (2,420 ft) of 15.9-lbm/gal cement packer was installed through CT in the 4 1/2- and 9 5/8-in. casing annulus and 656 ft of cement plug on the CR in the 4 1/2-in. tubing.\u0000 The use of 1.75-in. OD CT and catenary system effectively overcame the deck space and load bearing constraint of the platform while the 125K unit was used for improved CT reach and higher injector snub/pull capacity. Post-job shut-in tubing and casing pressures, quantity of cement slurry pumped, and extended flow test have proven the success of the design and procedure implemented. The operation was executed successfully using CT compared to the more expensive option of workover rig options for field redevelopment.","PeriodicalId":11110,"journal":{"name":"Day 2 Tue, August 06, 2019","volume":"375 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-08-05","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"80563973","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Effect of Water Salinity on Crude Oil Viscosity in Porous Media at Varying Temperatures","authors":"N. Ogolo, Daniel O. Adesina, George O. Akinboro, M. Onyekonwu","doi":"10.2118/198758-MS","DOIUrl":"https://doi.org/10.2118/198758-MS","url":null,"abstract":"\u0000 Viscosity is one major property of crude oil that is highly dependent on temperature and affects production operations. But temperature is not the only factor that affects oil viscosity; other factors include oil composition, pressure and dissolved gas. However, it has been observed that water salinity can also affect crude oil viscosity. It is therefore imperative that the effect of water salinity on crude oil viscosity be studied since water injection schemes using produced water or sea water is a common practice because it is economical and efficient in oil displacement from porous media.\u0000 This paper studies the effect of water salinity on crude oil viscosity at temperatures of 30°C, 70°C and 110°C. Sand samples were flooded with crude oil of known viscosity and brine of different salinity values ranging from 30g/l to 70g/l, after which the oil viscosities were determined again as well as the brine density. The flooding experiments were conducted like relative permeability experiments under steady state with an overburden pressure of 3000psi, using a standard core flooding equipment at a flow rate of 2ml/min.\u0000 The experimental results show that water salinity can increase crude oil viscosity. It was observed that the viscosity of the oil varied from 0.5cp to 2.3cp at different water salinity levels which could have been as a result of the chemical interaction between the two fluids. The effect of water salinity on the oil viscosity was more obvious at 30°C than at 70°C and 110°C, indicating that temperature could have played a vital role in the interaction process. On the other hand, the variation in water density after the oil-water interaction was more significant at higher temperatures than at 30°C. It was also observed that the maximum oil viscosity at 30°C was 2.26cp at 50g/l water salinity while 30g/l salinity gave the highest viscosity values of 1.29cp and 1.06cp for 70°C and 110°C respectively. This stresses the importance of conducting such studies with water samples intended to be used for water injection. It is therefore recommended that the effect of water salinity on crude oil viscosity be studied before embarking on any water injection scheme since high oil viscosity is not desired during oil production operations.","PeriodicalId":11110,"journal":{"name":"Day 2 Tue, August 06, 2019","volume":"57 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-08-05","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"82261343","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"In-Situ Burning As An Oil Spill Control Measure And Its Effect On The Environment","authors":"A. Ekperusi, A. Onyena, Marvellous Y. Akpudo, Chibuike C. Peter, Christiana O. Akpoduado, O. H. Ekperusi","doi":"10.2118/198777-MS","DOIUrl":"https://doi.org/10.2118/198777-MS","url":null,"abstract":"\u0000 In-situ burning (ISB) is a process of burning crude oil at the point of spill, as a containment measure for oil spill control. It is usually applied as one of the last resort to prevent spilled oil from reaching ecologically sensitive habitats and recreational activities in coastal areas. While booms, skimmers and dispersants may be very expensive and difficult to deploy, ISB is relatively inexpensive, making it attractive to oil spill responders. ISB can be applied in marine, coastal, freshwater, arctic and terrestrial environment. Factors affecting burn efficiency include water density, type of oil, slick thickness, degree of emulsification and weathering, flame coverage, wind speed and wave action. Although ISB has been very successful in removing spilled oil from polluted environment, there are great concerns about the transport and fate of emissions and residues from the burned oil, on the environment, biodiversity and public health. Potential air pollutants from oil burning include particulate matter, nitrogen oxide, sulphur dioxide, carbon monoxide, carbon dioxide, volatile organic compounds, and mixtures of various polycyclic aromatic hydrocarbons. Many developing nations lack the legal and regulatory frameworks, the contingency planning process and human resources to monitor the implementation of ISB in the oil and gas industry, making the practice very complicated and of imminent danger to society. There is also need to develop alternative measures to ISB in order to mitigate the effects on the environment and human population.","PeriodicalId":11110,"journal":{"name":"Day 2 Tue, August 06, 2019","volume":"27 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-08-05","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"82320414","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Artificial Bee Colony ABC a Potential for Optimizing Well Placement – A Review","authors":"E. Okoro, O. Agwu, D. I. Olatunji, O. Orodu","doi":"10.2118/198729-MS","DOIUrl":"https://doi.org/10.2118/198729-MS","url":null,"abstract":"\u0000 Many optimization tools exist for well placement into reservoirs for maximum oil recovery. Conventional tools such as simulated annealing, response surface technology, gradient-based optimization, mixed integer programming etc. abound. However, artificial intelligence optimization tools have emerged over the years and are gaining ground. Artificial bee colony (ABC) has become one of the most common optimization methods in the domain of Artificial Intelligence since it was first conceived in the early nineties. As a result, avalanches of researches to its credit in well placement optimization exist. This paper therefore, highlighted conventional well placement optimization tools and also reviewed the artificial intelligence based optimization tools especially ABC and hybrids of ABC Algorithms formulated for well placement and compared them with each other using four basic criteria. The review has shown that ABC algorithms are very efficient in handling the placement of wells in reservoirs during well planning. This work therefore opens up a new vista in the area of well placement optimization and is therefore recommended to anyone looking for a pivot on the well placement optimization discussion.","PeriodicalId":11110,"journal":{"name":"Day 2 Tue, August 06, 2019","volume":"367 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-08-05","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"77793773","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"A Geomodel for Pore Pressure Prediction Based on A Viscoelastic Compaction Law","authors":"Roland I. Nwonodi, A. Dosunmu","doi":"10.2118/198730-MS","DOIUrl":"https://doi.org/10.2118/198730-MS","url":null,"abstract":"\u0000 It is important to develop a model that simulates in situ pore pressure profile especially in an overpressured interval mainly because of wellbore instability, hydraulic fracturing treatment, lost circulation, kick, and blowout. The current methodology for predicting pore pressure depends on the Terzaghi's total stress but requires the accurate determination of the effective stress in the rock. The sedimentary processes occurring in a basin put the rock under compaction, which can be viscoelastic. The normal-compaction methods of predicting pore pressure consider only mechanical compaction, but viscous compaction is important to consider, especially beyond 2000 meters of the subsurface. In this study, a model for predicting pore pressure was developed by applying an effective stress law that considers viscoelastic compaction into the Terzaghi's stress equation. From the relationship defining effective stress and the rate of deformation, the author posed an expression for the total effective stress in terms of time. The applicable boundary condition was with respect to the transit time through the rock. Using transit time data for a Gulf Coast wellbore at 10,000 ft yielded a pressure gradient of 0.885 psi/ft, which compares to 0.863 psi/ft obtained from the modified Eaton's model and 0.9132 psi/ft obtained from the Zhang model. Another pressure required for a wellbore at 30,000 ft yielded a pressure gradient of 0.535 psi/ft, which compares with 0.52 psi/ft obtained from measured formation pressure. Thus, the results indicate that the viscoelastic compaction accurately defines the pore pressure profile in a rock. Furthermore, simulation results indicate that the most important variable affecting pore pressure is the overburden stress.","PeriodicalId":11110,"journal":{"name":"Day 2 Tue, August 06, 2019","volume":"97 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-08-05","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"80729620","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Impact of Geological Interpretation on Reservoir 3D Static Model: Workflow, Methodology Approach and Delivery Process","authors":"A. Agi, Afeez O. Gbadamosi, R. Junin, S. Kampit, Azza Hashim Abbas, J. Gbonhinbor","doi":"10.2118/198719-MS","DOIUrl":"https://doi.org/10.2118/198719-MS","url":null,"abstract":"\u0000 The traditional method of geologic modelling requires the interpretation of geological sections during digitization. But this traditional method has its limitations, the main limits are; it is usually time consuming and the model produced is unique to each individual geologist interpretation and may not be easily replicated by others. This study proposes an alternative workflow method for modelling, constructing and interpreting 3D geologic static model with multi-source data integration. The volume base method (VBM) was used to construct the 3D model. The combination of deterministic and probabilistic methods was used to model the facies workflow process to capture the geometrics of depositional environmental element. The truncated Gaussian simulation method was used with vertical trends option to obtain vertical transitional lithofacies in most of the reservoirs. Verification of results and detailed discussion of the proposed workflow and methodology is based on comparison with the conventional method. The saturation height function (SHF) equation applied to the water saturation model and permeability model improved the 3-D properties modelling workflow. The pillar gridding process was identified as the stage that increases the timeframe in 3-D modelling workflow. The results have proven to improve the overall timeframe and maximize the value of the field studies. The proposed method can be applied to a broad and complex geologic area. And is useful for marginal field development, by contributing economically and improving the deliverability of the entire project.","PeriodicalId":11110,"journal":{"name":"Day 2 Tue, August 06, 2019","volume":"53 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-08-05","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"75072073","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Evaluating the Performance of Local Anionic Emulsifier as a Possible Emulsifier for Synthetic-Based Mud System for Drilling Operations","authors":"R. Amorin, E. Broni-Bediako, Joel Bright Adanvor, Prince Opoku Appau","doi":"10.2118/198817-MS","DOIUrl":"https://doi.org/10.2118/198817-MS","url":null,"abstract":"\u0000 In the process of formulating oil-based muds, emulsifiers or surfactants are added to help build a strong oil-water emulsion. Currently, all the emulsifiers used in mud formulation in Ghana are imported increasing drilling cost. This also do not promote the local content and local participation policy of the country in the oil and gas sector. There are equally potential local emulsifiers that could be used in these mud formulations to reduce cost. This research, therefore, evaluated the performance of local anionic surfactant as a possible emulsifier for an ester-based oil mud system for drilling operations. A Synthetic-Based Mud (SBM) was formulated with varying concentrations of both local (L) and commercial (C) emulsifiers from 0% to 100% at a step of 25% after which their rheological properties evaluated. The rheological properties were evaluated for unaged samples at temperatures of 80 °F, 120 °F, 180 °F and aged samples at a temperature at 180 °F. The performances of the mud samples were tested using Gel Strength at 10 seconds and 10 minutes, Plastic Viscosity, Yield Point and pH at each varied concentration of emulsifier following closely the American Petroleum Institute (API) standard test procedures. The overall performances of the mud samples in order of descending were; BL100% > AC100% > EC25%L75% > CC50%L50% > DC75%L25%. It was observed that the local emulsifier performed equally well and even better than the commercial emulsifiers at the test conditions presenting the local emulsifier as a potential emulsifier for the formulation of SBMs for the oil and gas industry.","PeriodicalId":11110,"journal":{"name":"Day 2 Tue, August 06, 2019","volume":"1 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-08-05","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"87053917","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"The Loss of Primary barrier: An Integrated Approach of Downhole Leak Location and Quantification. Case Study","authors":"M. Volkov, A. Yurchenko, Remke Ellis","doi":"10.2118/198838-MS","DOIUrl":"https://doi.org/10.2118/198838-MS","url":null,"abstract":"\u0000 Failure of the primary barrier in most cases results in observable sustained annulus pressure. For other such cases, sustained annulus pressure may not result, and leak associated fluid movement remains confined to deeper intervals, for example as cross flows.\u0000 This manuscript introduces a comprehensive approach to assess the current status of primary and secondary barriers and, for this case of integrity loss, to quantify the downhole leaks rates. The assessment includes: Determining individual pipe wall thickness of first two concentric metal barriers using electromagnetic pulse logging techniqueSpectral Noise Logging to locate the active leaks and to verify the sealing integrity of cement barriersHigh Precision Temperature logging for downhole leak rate quantification utilizing temperature modeling\u0000 The paper contains the physics of measurement, lab and field tests of the barrier assessment technologies, followed with a case study: A single string gas producer, with sustained A-annulus pressure. Additional survey findings allowed the identification and quantification of a crossflow resulting from leaks.","PeriodicalId":11110,"journal":{"name":"Day 2 Tue, August 06, 2019","volume":"37 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-08-05","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"90241113","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Experimental Study on the Effect of Undulating Pipeline on Sand Transport in Multiphase Flow","authors":"N. E. Okeke, Osho Adeyem, A. Archibong-Eso, Y. Baba, A. Aliyu, E. Aluyor, H. Yeung","doi":"10.2118/198722-MS","DOIUrl":"https://doi.org/10.2118/198722-MS","url":null,"abstract":"\u0000 Previous research work has shown that sand production with hydrocarbons has helped to increase the productivity of oil wells. However, this poses difficulties during shut down and start-up operations due to sand deposition and are aggravated when the pipelines are undulating. The hilly-terrain geometry of pipelines strongly affects multiphase flow regimes hence the need to study sand transport characteristics as it is vital in efficient pipeline design. The aim of this research work is to experimentally investigate the flow hydrodynamics that exist during sand transport in multiphase flow at different sand concentration. A 2-inch dip facility which consists of a downhill pipeline section, a lower elbow (dip) and an uphill pipeline at inclination angles of 24° is used in the study. Extensive data were collected and analysed from continuous measurement of instantaneous liquid and sand hold up using conductivity rings and flow visualisation using a high speed camera. Results show that five different flow patterns were obtained from the sand-water test both via visual observation and from the conductivity rings data namely: full suspension, streak, saltation, sand dunes and sand bed. The knowledge of flow at minimum transport condition and full suspension establishes the erosion rate over the life span of the pipeline. In contrast, the sand holdup measurement and sand dune regime which was uniquely identified using the conductivity ring method would help overcome the limitation of sand measurement in pipeline. Also, the Sand-Air-Water experiment carried out shows the influence of the pipe geometry and multiphase flow regimes on sand transport in multiphase transport pipelines.","PeriodicalId":11110,"journal":{"name":"Day 2 Tue, August 06, 2019","volume":"29 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-08-05","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"90333623","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}