Day 1 Mon, June 25, 2018最新文献

{"title":"A Newly Developed Mathematical Model to Predict Hydrolyzed Polyacrylamide Crosslinked Polymer Gel Plugging Efficiency in Fractures and High Permeability Features","authors":"Sherif Fakher, B. Bai","doi":"10.2118/191180-MS","DOIUrl":"https://doi.org/10.2118/191180-MS","url":null,"abstract":"\u0000 Reservoir heterogeneity is one of the most challenging problems facing the hydrocarbon industry nowadays. It results in excess water production and a substantial reduction in oil recovery from water flooding applications. Gel treatment is one of the most successful applications to overcome reservoir heterogeneity problems by plugging high permeability features in a reservoir. One of the most widely used gels is the Hydrolyzed Polyacrylamide-Chromium Acetate Gel (HPAM/CrAc). This research uses data from 70 sources, including more than 1050 experiments, to perform a thorough data analysis to understand the conditions under which this gel is mainly applied. Histograms, and boxplots were generated revealing the ranges under which this gel can be applied, and the frequency of each range. The histograms and boxplots are each divided into the gel properties, and the core and sand pack properties, thus revealing both the chemical and rock properties' ranges. Three dendrograms were also developed based on their equivalent cluster plots generated. The dendrograms can show the different ranges at which the data was distributed and also tell the extent to which each range is related to the other. A mathematical model was also generated and validated in this study. This model gives a relation between the polymer concentration and the oil residual resistance factor (Frro). This model is extremely important since it can predict the effect of polymer concentration on the reduction of the oil permeability, which can help avoid the excessive reduction in oil permeability. The gel was found to have very good disproportionate permeability reduction (DPR), which indicates that it can reduce the permeability of water much more that the permeability of oil. This research can help in revealing the conditions under which the HPAM/CrAc gel can be applied, which in turn can significantly improve the design of field projects.","PeriodicalId":352851,"journal":{"name":"Day 1 Mon, June 25, 2018","volume":"20 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2018-06-22","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"114269296","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":"Low Salinity Water Injection in a Clastic Reservoir in Northeast Brazil: An Experimental Case Study","authors":"A. Almeida, Rajan G. Patel, Carolina Arambula, J. Soares, G. Costa, M. Embiruçu","doi":"10.2118/191257-MS","DOIUrl":"https://doi.org/10.2118/191257-MS","url":null,"abstract":"\u0000 Several researchers have demonstrated in laboratory experiments and field applications that reducing the concentration of salts and the content of multivalent cations in the injection water may increase oil recovery. This study evaluates the performance of low salinity water injection (LSWI) in oil recovery using a crude oil and synthetic formation water of a sandstone reservoir in northeast Brazil. Two Botucatu sandstone core samples of 6 in of length and 2 in of diameter were used for the coreflooding experiments. The fluids used included a light crude oil sample, and synthetic formation water (SFW) produced from the four main salts of the original formation water (NaCl, KCl, CaCl2, and MgCl2). In Core 1, two injections were carried out at an average reservoir temperature of 60 °C, one using SFW with 200,000 mg/l as secondary recovery mode, and one using SFW diluted 40 times (40xd_SFW) resulting in a low salinity water of 5,000 mg/l as tertiary recovery mode. In Core 2, 40xd_SFW was injected at the same temperature to compare the high and low salinity water effects in the secondary mode. Moreover, zeta (ζ) potential measurements on Botucatu sandstone powder were performed in 6 dilutions of the SFW and deionized water. The experimental results demonstrated an increase in oil recovery and pH when 40xd_SFW was injected in secondary and tertiary modes. The effluent ionic concentration from Core 1 showed the reduction of Ca2+ during HSWI, indicating its adsorption on the rock surface. Most remarkably, Ca2+ concentration increases and the Na+ concentration decreases in the effluent samples in the first LSWI pore volume injected, which suggested ionic exchange of calcium for sodium on the rock surface. Furthermore, Fe2+/Fe3+ and traces of Al3+ were observed in the effluent demonstrating the occurrence of fine migration in SFW and 40xd_SFW. The magnitude of negative ζ potential on Botucatu sandstone increases as the salinity of the brine solutions decreases. Based on that experimental study, it is noticed that a set of LSWI mechanisms occurr simultaneously in Botucatu sandstone, and oil and brine samples from Recôncavo Basin, indicating a potential of application for LSWI in similar Brazilian oil reservoirs.","PeriodicalId":352851,"journal":{"name":"Day 1 Mon, June 25, 2018","volume":"51 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2018-06-22","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"125531882","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":"History Matching of Naturally Fractured Reservoirs Using Pressure Transient Analysis and a Case Study","authors":"R. Vaughan, J. Hicks, Efrain Chasqui, Javier Velarde","doi":"10.2118/191229-MS","DOIUrl":"https://doi.org/10.2118/191229-MS","url":null,"abstract":"\u0000 This paper presents a modelling workflow to efficiently history match naturally fractured reservoirs using Pressure Transient Analysis (PTA) with application to a complex naturally fractured sandstone reservoir.\u0000 Incorporated in the modelling workflow is the use of deconvolution to streamline the history matching process. To ensure this workflow is flexible to mature fields with interference between wells, a work around to achieve a similar output to multi-well deconvolution is presented.\u0000 The modeling workflow was successfully applied to a case study resulting in reduction of computer processing time by around 60%. The product of this workflow was not just a single dual-porosity model which best matched the historical data-set, but a suite of models which sample the range of possibilities. From the multiple history matched models, the low (P90), mid (P50) and high case (P10) models were selected statistically.\u0000 Fracture porosity is shown to be the input parameter with largest impact on the pertinent simulation outputs in the case study such as time to water breakthrough, pressure match and recoverables. As such, time should be spent gathering and processing data to narrow the uncertainty range. However, care should be taken not to reduce the range prematurely as fracture porosity estimation is a source of wide uncertainty.\u0000 Additionally, the case study highlights that horizontal anisotropy can have a significant impact on the field GIIP during the history matching process and consequently impact the reserves in a fractured field. In the case study, the introduction of horizontal anisotropy not only improved the history match but also increased the field GIIP post-history match by around 30%. The value in studying anisotropy within a fractured field and its inclusion into modeling is clearly demonstrated.\u0000 This paper brings together various innovative data interpretation approaches and modeling techniques and presents them in an applied workflow. The workflow shows the practicing engineer how they can best interpret and utilize the available data-sets through the application of PTA. The result is not only a better history match, but also a more efficient process which provides a statistical representation of the likely possibilities of the naturally fractured system.","PeriodicalId":352851,"journal":{"name":"Day 1 Mon, June 25, 2018","volume":"77 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2018-06-22","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"114898939","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 Comparative Study of Mathematical Models for Fractured Reservoirs: Anomalous Diffusion and Continuum Approach.","authors":"M. Karim, M. Hossain, Mahamudul Hashan, S. Imtiaz","doi":"10.2118/191203-MS","DOIUrl":"https://doi.org/10.2118/191203-MS","url":null,"abstract":"\u0000 This study aims to determine an appropriate representative flow-model of a fractured reservoir after comparing two existing approaches: the anomalous diffusion and the continuum approach. A fractured reservoir is assumed in this paper that drains the fluid in transient condition, to a hydraulically fractured horizontal well. To investigate the comparison, dimensional consistency is maintained for both the anomalous diffusion and the continuum approach. Chen and Raghavan's (2015) model is considered as the anomalous diffusion model with modified boundary conditions. Continuum approach model considers the linear flow in a triple continuum structure that consists of matrix slab, micro-fracture, and hydraulic fracture. An analysis of the pressure response curves and the field data evaluates the proper approach for the analysis of the flow behavior. The solution of the wellbore pressure is derived in Laplace domain and is inverted by the Stehfest algorithm. Slope of the pressure response curve depends on the order of differentiation at the anomalous diffusion model. Conversely, the permeability of the hydraulic fracture controls the transient behavior at the continuum approach. The first set of analyses states that the continuum-based model considers the physical structure of the reservoir and increases the accuracy in the prediction of the reservoir behavior; however, more reservoir parameters are required for new continuum those are difficult to be determined. Alternatively, anomalous diffusion approach requires less parameter compare to the continuum approaches, but a high uncertainty exists in the precise determination of the order of the differentiation or the fractal exponent. The anomalous diffusion shows a good agreement with the synthesized field data at the early time whereas the continuum approach matches better at late time response.","PeriodicalId":352851,"journal":{"name":"Day 1 Mon, June 25, 2018","volume":"38 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2018-06-22","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"125556118","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 Upper Cretaceous of Trinidad, is there an Unconventional Source Rock Play?","authors":"C. Archie","doi":"10.2118/191168-MS","DOIUrl":"https://doi.org/10.2118/191168-MS","url":null,"abstract":"To date Trinidad has produced close to three billion barrels of oil from onshore and offshore fields. Formations penetrated range in age from the Lower Cretaceous to the Pleistocene. Ninety three wells have been drilled to the Cretaceous with varying degrees of success, these wells have identified whether source rock facies are present or absent across the island. Based on well and outcrop data, the Upper Cretaceous interval is shale dominated with occasional turbidite sandstone reservoirs and a siliceous mudstone locally known as \"Argilline\". Geochemical research by Kuarsingh (1986), Rodrigues (1987, 1988, 1993), Talukdar et al (1990), Requejo (1991), Persad et al (1993), Requejo et al (1994), Baseline/DGSI (2004) indicated that most of the hydrocarbons in Trinidad have been sourced from Type II kerogens contained in Cenomanian-Santonian and Aptian aged marine shales of the Naparima Hill and Gautier Formations respectively, Maastrichtian and Tertiary sediments are dominated by mainly woody and coaly kerogens. Total Organic Contents range from 0.1 to +- 9%. Rodrigues (1989) mapped the distribution of geothermal gradients identifying hot and cold areas, this data has implications for petroleum systems modeling, especially for the timing and top of the oil generating window. Royalty Lease Evaluation (RLE) analysis of oils produced from Upper Cretaceous sandstone and naturally fractured intervals (Specific gravity / API, viscosity, % Sulphur, % of products by distillation) give clues to the origin and history of these oils. Integration of these results and data can result in identification of areas with potentials unconventional source rock plays.","PeriodicalId":352851,"journal":{"name":"Day 1 Mon, June 25, 2018","volume":"15 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2018-06-22","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"125326361","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 Novel Digital Approach to Predict Production Rates from PCP Wells","authors":"J. Álvarez, O. Espinola, Christian Ramírez, A. Torres","doi":"10.2118/191228-ms","DOIUrl":"https://doi.org/10.2118/191228-ms","url":null,"abstract":"\u0000 Progressive cavity pumps (PCP) have been used as artificial lift system for heavy oil lifting, low productivity wells and other challenging conditions which are common characteristics of brownfields. In addition to those conditions, there is the current complicated economic environment in which operating companies seek to reduce investments while enhancing field production operations with low-cost solutions aiming to increase the overall's field recovery factor.\u0000 The initial step when trying to enhance field production operations in wells operating with PCPs as artificial lift system is performing a well-level analysis. During this analysis, the existing operational conditions and its corresponding production are evaluated. The continuity and accuracy of this analysis is highly dependent on the data input for analysis purposes. For instance, the rate of production is required as input and due to the nature of operation in brownfields, this value is not measured with the required frequency needed for performing a proper production enhancement analysis.\u0000 This paper aims to provide a simple, automated, and accurate way to perform a calculated rate of production that is cost effective and easy to maintain, capable of being used during field production operations enhancement analysis, and applicable to wells operating with PCPs as artificial lift in heavy oil conditions, using regression and analytical methods.\u0000 Both methods are being used part of a digital oilfield solution implemented in a heavy oil brownfield with telemetry-instrumented PCP wells. This solution is working inside a production operations platform that validates input data, manages different frequencies and types of data, and automatically calculates a production rate, which is then pushed to a visualization dashboard.\u0000 Results provide an accurate production rate estimate suitable for reservoir engineering analyses while providing insight for the production operations enhancement.","PeriodicalId":352851,"journal":{"name":"Day 1 Mon, June 25, 2018","volume":"120 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2018-06-22","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"134207128","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":"Evaluation of the Breakdown Pressure to Initiate Hydraulic Fractures of Tight Sandstone and Shale Formations","authors":"A. Ibrahim, H. Nasr-El-Din","doi":"10.2118/191245-MS","DOIUrl":"https://doi.org/10.2118/191245-MS","url":null,"abstract":"\u0000 Hydraulic Fracturing has been used successfully in the oil and gas industry to enhance oil and gas production. Recent years have seen the great development of tight gas, coalbed methane, and shale gas. Different fluids were used as fracturing fluids in shale and sandstone formations, including the use of CO2, N2 and CO2 foam, slick water, crosslinked solutions, and oil-based fracturing fluids. The objective of this study is to develop an experimental setup to measure the breakdown pressure to initiate the fractures in shale and tight sandstone cores.\u0000 This study investigated the effect of injection flow rate, temperature, fluid viscosity, and fluid type on the breakdown pressure of different rock cores. 5 wt% KCl brine, slick water with a friction reducer, linear gel systems were used as a fracturing fluid. Kentucky, Scioto, Bandera, and Berea sandstone cores were used. Also, Mancos, Marcellus, and Barnett shale cores were used in this study. Finally, the behavior of the breakdown pressure was examined as a function of the back pressure (0, 100, 300 psi).\u0000 The preliminary results show that the breakdown pressure increased as the injection flow rate increased. Where the breakdown pressure increased from 438 to 1,000 psi as the flow rate increased from 5 to 10 cm3/min in case of 5 wt% KCl with Kentucky sandstone cores. The breakdown pressure increased in Marcellus shale to 1,800 psi in case of 5 wt% KCl at 5 cm3/min. As the fluid viscosity increased the breakdown pressure increased, it increased to 1,115 psi in case of 2 gptg friction reducer (5 cp) comparing to 5 wt% KCl (1.1 cp) case at 5 cm3/min. A straight line relationship was found between the breakdown pressure and the logarithmic scale of the fluid viscosity.\u0000 This study will give recommendations for the fluid viscosity, type, and the injection flow rate that will improve the efficiency of the hydraulic fracturing operation.","PeriodicalId":352851,"journal":{"name":"Day 1 Mon, June 25, 2018","volume":"18 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2018-06-22","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"114693450","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":"Performance of CO2/N2 Foam in Enhanced Oil Recovery","authors":"Mohamed Hassan, R. Gajbhiye","doi":"10.2118/191208-MS","DOIUrl":"https://doi.org/10.2118/191208-MS","url":null,"abstract":"\u0000 Carbon dioxide (CO2) flooding is one of the attractive enhanced oil recovery process. Although it has several advantages, it suffers from early gas breakthrough due to low mobility ratio. The early breakthrough and mobility ratio can be improved by foaming CO2 gas. But CO2 is unable to generate the foam especially at supercritical condition (1100 psi at 31.10C) which is generally found in the reservoir. The CO2 foam gets weaker and weaker with an increase in pressure. It reduces the macroscopic sweep efficiency and hence the ultimate recovery.\u0000 The difficulty of generating CO2 foam is overcome by adding N2 in a small fraction to enhance the foam generation of CO2 at supercritical conditions. This study shows how the addition of small quantity of N2 helps in generating the CO2 foam and performance of the novel CO2/N2 mixture foam in enhanced oil recovery.\u0000 The goal of this study is to evaluate the oil displacement process by a novel foam system in which the CO2 and N2 mixture constitutes the gaseous phase. The experiments were carried out by flooding the core with CO2/N2 foam by imposing the condition above the supercritical CO2. The supercritical CO2 becomes denser and unable to generate the foam. To generate foam nitrogen is added to carbon dioxide to improve the CO2 ability for generating CO2 foam at supercritical conditions.\u0000 The CO2/N2 foam performance is evaluated by comparing displacement efficiency of CO2 foam with CO2/N2 foam. In addition, the effect of foam quality by fixing the injection rate were investigated on CO2/N2 foam flooding performance.","PeriodicalId":352851,"journal":{"name":"Day 1 Mon, June 25, 2018","volume":"142 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2018-06-22","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"116344720","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}