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1
Wang, D., M. Maubert, G. A. Pope, P. J. Liyanage, S. H. Jang, K. A. Upamali, L. Chang et al. „Reduction of Surfactant Retention in Limestones Using Sodium Hydroxide“. SPE Journal 24, Nr. 01 (20.11.2018): 92–115. http://dx.doi.org/10.2118/194009-pa.
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Summary Geochemical modeling was used to design and conduct a series of alkaline/surfactant/polymer (ASP) coreflood experiments to measure the surfactant retention in limestone cores using sodium hydroxide (NaOH) as the alkali. Surfactant/polymer (SP) coreflood experiments were conducted under the same conditions for comparison. NaOH has been used for ASP floods of sandstones, but these are the first experiments to test it for ASP floods of limestones. Two studies performed under different reservoir conditions showed that NaOH significantly reduced the surfactant retention in Indiana Limestone. An ASP solution with 0.3 wt% NaOH has a pH of approximately 12.6 at 25°C. The high pH increases the negative surface charge of the carbonate, which favors lower adsorption of anionic surfactants. Another advantage of NaOH is that low concentrations of only approximately 0.3 wt% can be used because of its low molecular weight and its low consumption in limestones. Most reservoir carbonates contain gypsum or anhydrite, and therefore sodium carbonate (Na2CO3) will be consumed by the precipitation of calcium carbonate (CaCO3). As shown in the two studies, NaOH can be used in limestone reservoirs containing gypsum or anhydrite.
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Jiang, Qingchun, Weiming Wang und Qixia Lyu. „Characteristics and Controlling Factors of Tight Marl Reservoirs with an Eyelid-Shaped Structure of the First Member of the Deep Maokou Formation in Eastern Sichuan“. Energies 16, Nr. 5 (01.03.2023): 2353. http://dx.doi.org/10.3390/en16052353.
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Tight marl is a special type of unconventional oil and gas resource, and the study on its reservoir characteristics and controlling factors is of immense scientific significance. In this paper, 113 core samples of marl from Gouxi Area, Eastern Sichuan were selected. Based on organic carbon, pyrolysis, X-ray diffraction of whole rock, and X-ray diffraction of clay analysis, the reservoir evaluation of eyelid-shaped limestone in the first member of Maokou Formation was carried out. The results show that there are obvious differences between eyelid-shaped limestone reservoirs and eyeball-shaped limestone reservoirs in the target stratum. Eyelid-shaped limestone is mainly distributed in the lower members a and c of the first member of Maokou Formation. It could be the main reservoir of low porosity and permeability tight marl, as its developed apertures, micro-fractures, and pore throat structure are obviously better than that of the eyeball-shaped limestone. As eyelid-shaped limestone features obvious self-generation and self-storage characteristics, the deep-water and low-energy sedimentary environment provides it with a large amount of highly brittle minerals and clay minerals as well as a favorable reservoir-forming background for diagenetic evolution and organic matter adsorption of clay minerals in the later period. The transformation of sepiolite into talc through diagenesis provides a large number of shrinkage joints for the reservoir, which are an effective space for tight gas accumulation.
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Gorter, J. D., und J. M. Davies. „UPPER PERMIAN CARBONATE RESERVOIRS OF THE NORTH WEST SHELF AND NORTHERN PERTH BASIN, AUSTRALIA“. APPEA Journal 39, Nr. 1 (1999): 343. http://dx.doi.org/10.1071/aj98019.
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The Perth, Carnarvon, Browse, and Bonaparte basins contain Permian shallowmarine carbonates. Interbedded with clastic oil and gas reservoirs in the northern Perth Basin (Wagina Formation), and gas reservoirs in the Bonaparte Basin (Cape Hay and Tern formations), these carbonates also have the potential to contain significant hydrocarbon reservoirs. Limestone porosity may be related to the primary depositional fabric, or secondary processes such as dolomitisation, karstification, and fracturing. However, in the Upper Permian interval of the North West Shelf and northern Perth Basin, where there are no indications of significant preserved primary porosity in the limestones, all known permeable zones are associated with secondary porosity. Fractured Permian carbonates have the greatest reservoir potential in the Timor Sea. Tests of fractured Pearce Formation limestones in Kelp Deep–1 produced significant quantities of gas, and a test of fractured Dombey Formation limestone in Osprey–1 flowed significant quantities of water and associated gas. Minor fracture porosity was associated with gas shows in dolomitic limestones in Fennel–1 in the Carnarvon Basin, and fractures enhance the reservoir in the Woodada Field in the northern Perth Basin. Karst formation at sub-aerial unconformities can lead to the development of secondary porosity and caverns, as in the Carnarvon Basin around Dillson–1. Minor karst is also developed at the top Dombey Formation unconformity surface in the Timor Sea region.
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Permana, Aang Panji, und Sunarty Suly Eraku. „Kualitas Batugamping Gorontalo Sebagai Reservoir Air Tanah Berdasarkan Analisis Jenis Porositas“. EnviroScienteae 16, Nr. 1 (18.08.2020): 1. http://dx.doi.org/10.20527/es.v16i1.8993.
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The potential of limestone in Gorontalo City is not only the use of industrial minerals but also its availability as a reservoir of groundwater reservoirs. The availability of groundwater is the main focus in preserving the environment. For this reason, this research focuses on the quality of limestone reservoirs by analyzing limestone porosity. The purpose of this study was to determine the average porosity percentage, porosity type and porosity quality both semi-quantitative and qualitative. In order to achieve these objectives, two methods are used namely the field survey method and petrographic analysis. The results showed the average percentage of porosity quality of limestone as a reservoir of groundwater in the excellent category with the type of porosity is fracturing and growing (vugular).
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Jiangmin, Du, Zhang Xiaoli, Yu Yanqiu, Huang Kaiwei, Guo Hongguang, Zhong Gaorun, Yu Bowei und Zhao Yuanyuan. „Lacustrine Carbonate Reservoir Characteristics Research of Jurassic Da’anzhai Member in North Central Sichuan Basin“. Open Petroleum Engineering Journal 8, Nr. 1 (10.09.2015): 398–404. http://dx.doi.org/10.2174/1874834101508010398.
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Based on both macroscopic and microscopic characteristics of cores from Lower Jurassic Da’anzhai Member in north central Sichuan Basin, and combined with physical property data, a detail study has been conducted, which includes reservoir characteristics such as lithologic characters, physical properties, and reservoir space types, and control factors of reservoir development. The study suggests that, there are two typical kinds of reservoirs: crystalline shell limestone and argillaceous shell limestone. The reservoirs properties are poor with ultra-low porosity and low permeability, which can be significantly improved by fractures. Reservoir space type is pore-fracture, mainly constitutive of the micro-fractures accompanied by dissolved pores. The reservoir development is controlled by sedimentation, diagenesis and tectogenesis together. Shell beach and lacustrine slop are the favorable facies for reservoir development. Dissolution is the primary constructive diagenesis to improve reservoir porosity and permeability. Structural fractures are necessary for reservoir effectiveness and high production.
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Xin, Yongguang, Wenzheng Li, Hao Zhang, Han Tian, Xiaodong Fu und Zengye Xie. „Mechanisms by Which an Evaporated Lagoon Sedimentation System Controls Source–Reservoir Preservation in Lei32 Sub-Member Unconventional Oil and Gas“. Energies 17, Nr. 4 (19.02.2024): 964. http://dx.doi.org/10.3390/en17040964.
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The muddy limestone in the Lei32 sub-member of the Middle Triassic Leikoupo Formation in the well Chongtan 1 (CT1) of the Sichuan Basin has yielded promising industrial oil and gas production. This discovery has the potential to become a significant strategic reservoir in the future for oil and gas exploration in the Sichuan Basin. However, the understanding of hydrocarbon accumulation in the muddy limestone of the Lei32 sub-member remains insufficient, which poses limitations on further exploration selection and deployment strategies. This study focuses on the analysis of core samples and laboratory data in the wells CT1 and Jianyang 1 (JY1), aiming to investigate the source rock and reservoir characteristics of the muddy limestone in the Lei32 sub-member, as well as the primary controlling factors influencing the development of the source rock and reservoir. The results show that the Lei32 sub-member in the Central Sichuan Basin is an evaporated lagoon deposition; the tight argillaceous limestone and limy mudstone exhibit the characteristic of source–reservoir integration, belonging to a new type of unconventional oil and gas reservoir. The reservoir space of the argillaceous limestone and limy mudstone in the Lei32 sub-member primarily consists of inorganic and organic micro–nanopores and microfractures. The average porosity and permeability are 2.7% and 0.19 mD, indicating a low-porosity and low-permeability unconventional reservoir. The clay minerals and gypsum content are the important factors influencing reservoir porosity, and the fractures are key factors influencing permeability. This study will elucidate the specific features of hydrocarbon accumulation in the muddy limestone reservoirs of the Lei32 sub-member and provide insights into its exploration potential.
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Islam, Musfirat Najmun, Md Anwar Hossain Bhuiyan, Mohammad Solaiman, Md Sajjadul Islam Fahim und Zohur Ahmed. „Evaluation of Reservoir Properties of Sylhet Limestone of Jaintia Group, North-Eastern Sylhet, Bangladesh“. Dhaka University Journal of Earth and Environmental Sciences 12, Nr. 2 (24.06.2024): 119–37. http://dx.doi.org/10.3329/dujees.v12i2.73167.
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The Sylhet Limestone in the Bengal Basin, formed in the Eocene Epoch and known for its fossil content, is significant in understanding the reservoir characteristics. Despite exposure in Jaflong and Takerghat of the Bengal Basin, little research has been conducted on reservoir characteristics. This study aimed to comprehensively examine the Sylhet Limestone Formation, encompassing its crystalline upper and fossiliferous lower sections. It utilized field investigations and laboratory analyses to address the gaps of sporadic or insufficient earlier studies. A thorough examination of thin sections from the Sylhet Limestone, exposed in the Dauki River area, provides insights into the textural and mineralogical attributes and the presence of skeletal fossils within the limestone. Based on the analysis of thin sections, the limestones are categorized as Rudestones and Packstones. The porosity observed in the exposed rocks ranges from 5% to 12%, with most pores associated with interconnected fractures and joints. However, thin-section studies also indicate evidence of diagenetic recrystallization and calcite cementation. Hence, closely spaced, interconnected joints and fractures filled with diagenetic calcite might deteriorate the reservoir quality. Notably, this limestone exhibits fossilized specimens such as Nummulite, Discocyclina, Alveolina, Assilina, and Ostracoda, among others. The combination of the fossil assemblage, limestone texture, and composition strongly suggests that this limestone formation was deposited in a shallow marine environment with minimal sediment input under a warm and humid climate. The petrographic analysis of the limestones concludes that the upper portion of the formation is fine-grained while the lower part is coarse-grained. The Dhaka University Journal of Earth and Environmental Sciences, Vol. 12(2), 2023, P 119-137
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Widarsono, Bambang. „THE ROCK COMPRESSIBILITY CHARACTERISTICS OF SOME INDONESIAN RESERVOIR LIMESTONES“. Scientific Contributions Oil and Gas 37, Nr. 1 (14.02.2022): 1–14. http://dx.doi.org/10.29017/scog.37.1.615.
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Rock compressibility is an important formation rock properties. It infl uences various processesin reservoir and rock formations that encompass from sources of reservoir driving energy, changes inother reservoir properties, to land subsidence. Various studies have been performed and published, butno comprehensive studies have ever been performed on Indonesian reservoir rocks. This article presentsresults of such studies on Indonesian limestones, reservoir rocks that have contributed much to Indonesia’snational oil and gas production for decades. The study was carried out in order to study the characteristics oflimestone in its relation to rock porosity. A set of 84 limestone samples taken from fi ve productive formationsin Indonesia is used in the study. Some existing and widely known mathematical correlations/models are alsoused to assist the study. Some of the results show that the existing models are not always valid for some ofthe rocks, and therefore a new model is proposed for medium-hard and vuggy limestones. The results alsoshow that limestone characteristics are not related to rock types and place of origin, but instead to rockhardness and degree of vuggy pore presence.
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Dunnington, H. V. „Generation, migration, accumulation, and dissipation of oil in Northern Iraq“. GeoArabia 10, Nr. 2 (01.04.2005): 39–84. http://dx.doi.org/10.2113/geoarabia100239.
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ABSTRACT Most of the known oil accumulations of Northern Iraq probably originated by upward migration from earlier, deeper accumulations which were initially housed in stratigraphic or long-established structural traps, and which are now largely depleted. The earlier concentrations had their source in basinal sediments, into which the porous, primary-reservoir limestones pass at modest distances east of the present fields. Development of the region favored lateral migration from different basinal areas of Upper Jurassic and Lower-Middle Cretaceous time into different areas of primary accumulation. Important factors affecting primary accumulation included: (1) early emergence and porosity improvement of the reservoir limestones, followed by burial under seal-capable sediments; (2) the timely imposition of heavy and increasing depositional loads on the source sediments, and the progressive marginward advance of such loads; (3) progressive steepening of gradients trending upward from source to accumulation area; (4) limitation of the reservoir formations on the up-dip margin by truncation or by porosity trap conditions. In late Tertiary time, large-scale folding caused adjustments within the primary reservoirs, and associated fracturing permitted eventual escape to higher limestone reservoirs, or to dissipation at surface. The sulfurous, non-commercial crudes of Miocene and Upper Cretaceous reservoirs in the Qaiyarah area are thought to stem from basinal radiolarian Upper Jurassic sediments, which lie down dip, a few tens of miles east of these fields. Upper Cretaceous oils of Ain Zalah and Butmah drained upward from primary accumulations in Middle Cretaceous limestones, which were filled from basinal sediments of Lower Cretaceous age situated in a localized trough a few miles northeast of these structures. The huge Kirkuk accumulation, now housed in Eocene-Oligocene limestones, ascended from a precedent accumulation in porous Middle-Lower Cretaceous limestones, which drew its oil from globigerinal-radiolarian shales and limestones of the contemporaneous basin, a short distance east of the present field limits. Eocene-Oligocene globigerinal sediments, considered by some the obvious source material for Kirkuk oil, seemingly provided little or no part of the present accumulation. The reservoir formation may have been filled from these sources, to lose its oil by surface dissipation during the erosional episode preceding Lower Fars deposition. Upper Cretaceous basinal sediments probably contributed nothing to known oil field accumulations, though they may have subscribed to the spectacular impregnations of some exposed, Upper Cretaceous reef-type limestones. Neither Miocene nor pre-Upper Jurassic sediments have played any discernible role in providing oil to any producing field. Indigenous oils are thought to be negligible in the limestone-reservoir formations considered.
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Mahdi, Thamer. „Stratigraphic Reservoir Characterization of Ratawi Formation in Southern Iraq“. Iraqi Geological Journal 57, Nr. 2D (31.10.2024): 65–77. http://dx.doi.org/10.46717/igj.57.2d.5ms-2024-10-15.
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The Early Cretaceous Ratawi Formation in the Arabian Plate consists of sandstone and carbonate reservoirs. In Iraq, the Ratawi Formation is productive in several oilfields of the Mesopotamian Basin in southern Iraq. Selected wells are studied by using well logs of the formation and using a sequence stratigraphic approach to predict the distribution of reservoirs in the Mesopotamian Basin. The combination use of Gamma-ray, Neutron, Density, and Sonic logs shows that the major lithologies of the Ratawi Formation are shale, limestone, and sandstone. The calculated effective porosity and volume of shale indicate that the best reservoir quality occurs in clean sandstone units, characterized by high effective porosity and low shale volume. Limestone units have lower reservoir quality as low effective porosity and high shale volume values are recorded. The effect of shale is recognizable in reducing reservoir quality as the shale volume decreases effective porosity. The sequence stratigraphic hierarchy of the Ratawi Formation includes three transgressive cycles. The regressive cycle (R1) hosts the main reservoirs that occur as prograding sandstone channels or bars. The cap units for these reservoirs consist of transgressive limestone or shale units. Due to the accommodation increase and weak sand influx of the middle and upper regressive cycles (R2 and R3), reservoir progradation shifted westward of the study area. The occurrence of isolated or stacked sandstone reservoirs as channels or bars increases the possibility of finding stratigraphic traps.
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Taylor, Kevin C., Hisham A. Nasr-El-Din und Sudhir Mehta. „Anomalous Acid Reaction Rates in Carbonate Reservoir Rocks“. SPE Journal 11, Nr. 04 (01.12.2006): 488–96. http://dx.doi.org/10.2118/89417-pa.
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Summary It is generally assumed that the reaction of acid with limestone reservoir rock is much more rapid than acid reaction with dolomite reservoir rock. This work is the first to show this assumption to be false in some cases, because of mineral impurities commonly found in these rocks. Trace amounts of clay impurities in limestone reservoir rocks were found to reduce the acid dissolution rate by up to a factor of 25, to make the acid reactivity of these rocks similar to that of fully dolomitized rock. A rotating disk instrument was used to measure dissolution rates of reservoir rock from a deep, dolomitic gas reservoir in Saudi Arabia (275°F, 7,500 psi). More than 60 experiments were made at temperatures of 23 and 85°C and HCl concentration of 1.0 M (3.6 wt%). Eight distinctly different rock types that varied in composition from 0 to 100% dolomite were used in this study. In addition, the mineralogy of each rock disk was examined before and after each rotating disk experiment with an environmental scanning electron microscope (ESEM) using secondary and backscattered electron imaging and energy dispersive X-ray (EDS) spectroscopy. Acid reactivity was correlated with the detailed mineralogy of the reservoir rock. It was also shown that bulk anhydrite in the rock samples was converted to anhydrite fines by the acid at 85°C, a potential source of formation damage. Introduction A study of acid reaction rates and reaction coefficients of a dolomitic reservoir rock was recently reported by Taylor et al. (2004a). In that work, it was found that reaction rates depended on mineralogy and the presence of trace components such as clays. This paper examines in detail the relationship between acid reactivity and mineralogy of a deep, dolomitic gas reservoir rock. An accurate knowledge of acid reaction rates of deep gas reservoirs can contribute to the success of matrix and acid fracture treatments. Many studies of acid stimulation treatments of Formation K, a deep, dolomitic gas reservoir in Saudi Arabia, have been published (Nasr-El-Din et al. 2001, 2002a, 2002b; Bartko et al. 2003). It is generally assumed that the reaction of acid with limestone reservoir rock is much more rapid than acid reaction with dolomite reservoir rock during acidizing treatments. However, much of the reported data were obtained with pure limestones, dolomites, and marbles. These include calcite marble (CaCO3) (Lund et al. 1975; de Rozieres 1994; Frenier and Hill 2002), dolomite marble [CaMg(CO3)2] (Lund et al. 1973; Herman and White 1985), Indiana limestone (Mumallah 1991), St. Maximin and Lavoux limestones (Alkattan et al. 1998), Haute Vallée de l'Aude dolomite (Gautelier et al. 1999), Bellefonte dolomite (Herman and White 1985), San Andres dolomite (Anderson 1991), Kasota dolomite (Anderson 1991), and Khuff dolomite reservoir cores (Nasr-El-Din et al. 2002b). The effects of common acid additives on calcite and dolomite dissolution rates were reported in detail (Frenier and Hill 2002; Taylor et al. (2004b; Al-Mohammed et al. 2006). The effects of impurities such as clays on rock dissolution have not been reported.
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Wang, Yang, Yu Fan, Song Li, Zefei Lv, Rui He und Liang Wang. „A New Fracturing Method to Improve Stimulation Effect of Marl Tight Oil Reservoir in Sichuan Basin“. Processes 11, Nr. 11 (16.11.2023): 3234. http://dx.doi.org/10.3390/pr11113234.
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China’s argillaceous limestone reservoir has a lot of oil and gas resources, and hydraulic fracturing of the argillaceous limestone reservoir faces many difficulties. The first problem is that the heterogeneity of the argillaceous limestone reservoir is strong, and it is difficult to optimize fracturing parameters. The second problem is that there are a lot of natural fractures in the argillaceous limestone reservoir, which leads to a lot of fracturing fluid loss. The third problem is that the closure pressure of the argillaceous limestone reservoir is high, and the conductivity of fractures decreases rapidly under high closure pressure. The last problem is that the fracture shape of the argillaceous limestone reservoir is complex, and the law of proppant migration is unclear. The main research methods in this paper include reservoir numerical simulation, fluid-loss-reducer performance evaluation, flow conductivity tests and proppant migration visualization. To solve the above problems, this paper establishes the fracturing productivity prediction model of complex lithology reservoirs and defines the optimal hydraulic fracturing parameters of the argillous limestone reservoir in the Sichuan Basin. The 70/140 mesh ceramide was selected as the fluid loss additive after an evaluation of the sealing properties of different mesh ceramides. At the same time, the hydraulic fracture conductivity test is carried out in this paper, and it is confirmed that the fracture conductivity of 70/140 mesh and 40/70 mesh composite particle-size ceramics mixed according to the mass ratio of 5:5 is the highest. When the closure pressure is 40 MPa, the conductivity of a mixture of 70/140 mesh ceramic and 40/70 mesh ceramic is 35.6% higher than that of a mixture of 70/140 mesh ceramic and 30/50 mesh ceramic. The proppant migration visualization device is used to evaluate the morphology of the sand dike formed by the ceramsite, and it is clear that the shape of the sand dike is the best when the mass ratio of 70/140 mesh ceramsite and 40/70 mesh ceramsite is 6:4. The research results achieved a good stimulation effect in the SC1 well. The daily oil production of the SC1 well is 20 t, and the monitoring results of the wide-area electromagnetic method show that the fracturing fracture length of the SC1 well is up to 129 m.
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Kassab, Mohamed A., Ali El-Said Abbas, Mostafa A. Teama und Musa A. S. Khalifa. „Prospect evaluation and hydrocarbon potential assessment: the Lower Eocene Facha non-clastic reservoirs, Hakim Oil Field (NC74A), Sirte basin, Libya—a case study“. Journal of Petroleum Exploration and Production Technology 10, Nr. 2 (24.09.2019): 351–62. http://dx.doi.org/10.1007/s13202-019-00773-8.
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Abstract Petrophysical assessment of Facha Formation based on log data of six wells A1, A3, A4, A5, A8 and A13 recorded over the entire reservoir interval was established. Hakim Oil Field produces from the Lower Eocene Facha reservoir, which is located at the western side of Sirte basin. Limestone, dolostone and dolomitic limestone are the main lithologies of the Facha reservoir. This lithology is defined by neutron porosity—density cross-plot. Noteworthily, limestone increases in the lowermost intervals of the reservoir. Structurally, the field is traversed by three northwest–southeast faults. The shale of the Upper Cretaceous Sirte Formation is thought to be the source rock of the Facha Formation, whereas the seals are the limestone and anhydrite of the Lower Eocene Gir Formation. In this study, the Facha reservoir’s cutoff values were obtained from the cross-plots of the calculated shale volume, porosity and water saturation values accompanied with gamma ray log data and were set as 20%, 10% and 70%, respectively. Isoparametric maps for the thickness variation of net pay, average porosity, shale volume and water saturation were prepared, and the authors found out that the Facha Formation has promising reservoir characteristics in the area of study; a prospective region for oil accumulation trends is in the north and south of the study area.
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Hafiz, Surya Darma, Ahmad Helman Hamdani, Budi Muljana und Moeh Ali Jambak. „Effect of diagenetic events on limestone reservoir quality: Case study of Parigi formation, Northwest Java basin“. BIO Web of Conferences 73 (2023): 04009. http://dx.doi.org/10.1051/bioconf/20237304009.
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Limestone is a sedimentary rock with high heterogeneity. This is triggered by diagenetic processes that affect the quality of limestone during its formation. The high uncertainty in limestone porosity values is also influenced by diagenetic processes. The Parigi Formation is a carbonate rock located in the Northwest Java Basin and has been proven to be a carbonate reservoir rock. Petrographic analysis was conducted to observe the appearance resulting from diagenetic processes. The studied area's limestone has two facies: clastic facies and reef facies. The limestone of clastic facies is white to greyish, consisting of skeletal fragments or shell fragments, with some places contains fragmented coral fragments. It is grain-supported, massive, poorly sorted, with fragment sizes ranging from 1mm-8mm and in some places 10cm-20cm. The reef facies of limestone are generally white to greyish colour, compact/massive, without cavities, and shows the body structure of coral/reef. The processes occurring in the Parigi Formation limestone, based on thin-section data, include cementation and neomorphism, which are commonly found in thin section LP 7 and LP 10. Cementation and neomorphism lead to a decrease in porosity in the limestone. Samples LP 1 - LP 5 show extensive dissolution, resulting in vuggy cavities/porosity. These limestone samples have high porosity values. The transformation of fossils into new crystals or recrystallization processes also reduces the limestone's porosity. Some samples also show that the cavities in the Parigi Formation limestone have been filled by calcite cements, thus closing the pores. This leads to poor quality limestone. In conclusion, the heterogeneous nature of limestone is significantly influenced by diagenetic processes. Petrographic analysis of the Parigi Formation limestone revealed the occurrence of cementation, neomorphism, dissolution, and recrystallization processes, all of which have implications for porosity and reservoir quality.
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Ahmed, Zheno Kareem, und Halkawt Ismail Ismail M-Amin. „Analyzing of Drill Stem Test (DST) Result for Dual Porosity Limestone Reservoir“. Kurdistan Journal of Applied Research 2, Nr. 3 (27.08.2017): 240–51. http://dx.doi.org/10.24017/science.2017.3.45.
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The aim of this paper is to discuss and evaluate the result of DST which was conducted in a limestone reservoir of an oil field at the depth interval 3764.29-3903.0 meter in well-1 to evaluate the dynamic characteristics of the reservoirs, for instance: skin effect, permeability, wellbore storage, reservoir boundary and average reservoir pressure. Reservoir Pressure profiles has been recorded for both Buildup and draw down intervals. Semi-log and log-log coordinates have been used to plot the pressure signature date of both buildup period and its derivative to improve diagnostic and Horner plot. In addition, a dual porosity reservoir and infinite acting characteristic was discovered as a result of the well test data interpretation. Wellbore storage, skin factor and transient flow effects have been detected in the DST analysis on the dual porosity behavior due to phase re distribution. Using final buildup sections, the flow parameters of dual porosity reservoir were determined as the flow between fissure and matrix was (7.558 x 10-6) while, the storability ratio between fissure and matrix was calculated as 0.3 and permeability is 102 MD for both matrix and the fissure together. However, negative value of skin factor mostly appears in double porosity limestone reservoirs, positive skin factor of the reservoir has been observed in this study. It can be considered that the positive skin factor can be resulted in either the formation was partially penetrated and /or wells were not cleaned up properly.
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Vukadin, Domagoj, Jasna Orešković und Csaba Kutasi. „Elastic Properties of Pannonian Basin Limestone under Different Saturation Conditions“. Energies 14, Nr. 21 (03.11.2021): 7291. http://dx.doi.org/10.3390/en14217291.
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Understanding elastic properties of reservoir rocks is essential for seismic modeling under different saturation conditions as well as lithology discrimination. Experiments on elastic properties of limestones are significantly less published compared to siliciclastic sedimentary rocks. The current study presents the results of laboratory measurements on Pannonian Basin limestone cores. The research was carried out for the first time for a hydrocarbon reservoir in the Bjelovar Depression, located in the southern part of the Pannonian Basin. Ultrasonic velocity measurements and determination of dynamic elastic properties were performed on limestone plugs, in dry and saturated condition under different confining pressure steps. Based on the results obtained in laboratory conditions, an empirical relationship between shear wave velocity (Vs) and compressional wave velocity (Vp) has been defined. The saturated samples show an effect of shear modulus weakening, while three samples have a shear modulus strengthening effect. Two models were used in the interpretation of the measured data, the Kuster and Toksöz and the Xu-Payne model. The results show that the Xu-Payne model describes the data well and the dominant pore type system in the limestone samples can been identified. The interpretation revealed an interparticle pore system with a fraction of microcracks from 20% to 35%. The results have helped to understand the elastic properties of limestones from the southern part of the Pannonian Basin, which are necessary for any process of reservoir characterization, such as porosity distribution and permeability variation.
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Cantrell, Dave L., und Royal M. Hagerty. „Reservoir rock classification, Arab-D reservoir, Ghawar field, Saudi Arabia“. GeoArabia 8, Nr. 3 (01.07.2003): 435–62. http://dx.doi.org/10.2113/geoarabia0803435.
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ABSTRACT An integrated petrographic and petrophysical study of Arab-D carbonates in Ghawar field has provided a new reservoir rock classification. This classification provides a simple but practical method of dividing the complex carbonate rocks of the Arab-D into meaningful reservoir rock types. Each rock type has a distinct pore network as defined by porosity-permeability relationships and capillarity expressed as pore-size distributions and J-function curves. The classification divides the Arab-D carbonates into seven limestone and four dolomite rock types. The amount of matrix (lime mud) and the pore types are the primary controlling parameters for the limestones. The dolomites are divided according to their crystal texture. The seven limestone reservoir rock types are based on the values of five petrographic parameters: (1) the amount of cement, (2) the amount of matrix (lime mud), (3) the grain sorting, (4) the dominant pore type, and (5) the size of the largest molds. The amount of matrix is the most important of these five parameters. In general terms, six of these seven types fall into two broad families, A and B, each of which can then be subdivided into three members (Types I, II, and III) according to their matrix content. The first family, A, is a fairly coarse-grained, poorly sorted rock with relatively large molds. The second family, B, is a generally fine to medium-grained, well sorted rock with few or small molds. The seventh rock type contains more than 10 percent cement which modifies the pore size distribution enough to warrant a separate reservoir rock type. Each of the reservoir rock types exhibits a distinctive pore-size distribution and, in turn, Leverett J-function or capillarity. The seven types are also characterized by distinctive porosity-permeability relationships. The four dolomite reservoir rock types are classified according to their dolomite crystal texture, although stratigraphic position and porosity can also be effective in their classification. The four textures are: fabric preserving (Vfp), sucrosic (Vs), intermediate (Vi) and mosaic (Vm). The Vfp dolomite is only found in Zone 1 of the Arab-D where it is the major dolomite type. Vs dolomite occurs in dolomites with more than 12 percent porosity, Vm less than 5 percent and Vi between 5 and 12 percent. Vfp dolomites have pore systems similar to their precursor limestone but the pore systems of the other dolomite types are unique. A significant finding of this evaluation is that the micropore system in all major limestone rock types in Zones 1 and 2 (upper Arab-D) is consistently an order of magnitude larger than for the same rock types in Zones 3 and 4 (lower Arab-D). The increase in size is believed to be a result of increased leaching in the upper Arab-D. This difference suggests that rocks of similar type from the upper and lower Arab-D will behave differently in terms of their fluid flow and saturation characteristics, and will have different ultimate recoveries.
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Khan, Nasar, Imran Ahmed, Muhammad Ishaq, Irfan U. Jan, Wasim Khan, Muhammad Awais, Mohsin Salam und Bilal Khan. „Reservoir Potential Evaluation of the Middle Paleocene Lockhart Limestone of the Kohat Basin, Pakistan: Petrophysical Analyses“. International Journal of Economic and Environmental Geology 11, Nr. 1 (06.07.2020): 1–9. http://dx.doi.org/10.46660/ijeeg.vol11.iss1.2020.404.
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The Lockhart Limestone is evaluated for its reservoir potential by utilizing wireline logs of Shakardara-01 well from Kohat Basin, Pakistan. The analyses showed 28.03% average volume of shale (Vsh), 25.57% average neutron porosity (NPHI), 3.31% average effective porosity (PHIE), 76% average water saturation (Sw), and 24.10% average hydrocarbon saturation (Sh) of the Lockhart Limestone in Shakardara-01 well. Based on variation in petrophysical character, the reservoir units of the Lockhart Limestone are divided into three zones i.e., zone-1, zone-2 and zone-3. Out of these zones, zone-1 and zone-2 possess a poor reservoir potential for hydrocarbons as reflected by very low effective porosity (1.40 and 2.02% respectively) and hydrocarbon saturation (15 and 5.20%), while zone-3 has a moderate reservoir potential due to its moderate effective porosity (6.50%) and hydrocarbon saturation (52%) respectively. Overall, the average effective porosity of 3.31% and hydrocarbon saturation of 24.10% as well as 28.03% volume of shale indicated poor reservoir potential of the Lockhart Limestone. Lithologically, this formation is dominated by limestone and shale interbeds in the Shakardara-01 well. Cross-plots of the petrophysical parameters versus depth showed that the Lockhart Limestone is a poor to tight reservoir in Shakardara-01 well and can hardly produce hydrocarbons under conventional drilling conditions.
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Khan, Nasar, Imran Ahmed, Muhammad Ishaq, Irfan U. Jan, Wasim Khan, Muhammad Awais, Mohsin Salam und Bilal Khan. „Reservoir Potential Evaluation of the Middle Paleocene Lockhart Limestone of the Kohat Basin, Pakistan: Petrophysical Analyses“. International Journal of Economic and Environmental Geology 11, Nr. 1 (06.07.2020): 1–9. http://dx.doi.org/10.46660/ojs.v11i1.404.
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The Lockhart Limestone is evaluated for its reservoir potential by utilizing wireline logs of Shakardara-01 well from Kohat Basin, Pakistan. The analyses showed 28.03% average volume of shale (Vsh), 25.57% average neutron porosity (NPHI), 3.31% average effective porosity (PHIE), 76% average water saturation (Sw), and 24.10% average hydrocarbon saturation (Sh) of the Lockhart Limestone in Shakardara-01 well. Based on variation in petrophysical character, the reservoir units of the Lockhart Limestone are divided into three zones i.e., zone-1, zone-2 and zone-3. Out of these zones, zone-1 and zone-2 possess a poor reservoir potential for hydrocarbons as reflected by very low effective porosity (1.40 and 2.02% respectively) and hydrocarbon saturation (15 and 5.20%), while zone-3 has a moderate reservoir potential due to its moderate effective porosity (6.50%) and hydrocarbon saturation (52%) respectively. Overall, the average effective porosity of 3.31% and hydrocarbon saturation of 24.10% as well as 28.03% volume of shale indicated poor reservoir potential of the Lockhart Limestone. Lithologically, this formation is dominated by limestone and shale interbeds in the Shakardara-01 well. Cross-plots of the petrophysical parameters versus depth showed that the Lockhart Limestone is a poor to tight reservoir in Shakardara-01 well and can hardly produce hydrocarbons under conventional drilling conditions.
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Khan, Nasar, Imran Ahmad, Muhammad Ishaq, Irfan Jan, Wasim Khan, Muhammad Awais, Mohsin Salam und Bilal Khan. „Reservoir Potential Evaluation of the Middle Paleocene Lockhart Limestone of the Kohat Basin, Pakistan: Petrophysical Analyses“. International Journal of Economic and Environmental Geology 11, Nr. 01 (05.08.2024): 1–9. http://dx.doi.org/10.46660/ijeeg.v11i01.212.
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The Lockhart Limestone is evaluated for its reservoir potential by utilizing wireline logs of Shakardara-01well from Kohat Basin, Pakistan. The analyses showed 28.03% average volume of shale (Vsh), 25.57% average neutron porosity (NPHI), 3.31% average effective porosity (PHIE), 76% average water saturation (Sw), and 24.10% average hydrocarbon saturation (Sh) of the Lockhart Limestone in Shakardara-01 well. Based on variation in petrophysical character, the reservoir units of the Lockhart Limestone are divided into three zones i.e., zone-1, zone-2 and zone-3. Out of these zones, zone-1 and zone-2 possess a poor reservoir potential for hydrocarbons as reflected by very low effective porosity (1.40 and 2.02% respectively) and hydrocarbon saturation (15 and 5.20%), while zone-3 has a moderate reservoir potential due to its moderate effective porosity (6.50%) and hydrocarbon saturation (52%) respectively. Overall, the average effective porosity of 3.31% and hydrocarbon saturation of 24.10% as well as 28.03% volume of shale indicated poor reservoir potential of the Lockhart Limestone. Lithologically, this formation is dominated by limestone and shale interbeds in the Shakardara-01 well. Cross-plots of the petrophysical parameters versus depth showed that the Lockhart Limestone is a poor to tight reservoir in Shakardara-01 well and can hardly produce hydrocarbons under conventional drilling conditions.
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Rahman, Arief, und Rani Rahmawati. „Uji Laboratorium Sampel Core Plug untuk Menentukan Porositas, Permeabilitas dan Saturasi Minyak pada Reservoir Batugamping“. Jurnal Indonesia Sosial Teknologi 3, Nr. 07 (25.07.2022): 840–54. http://dx.doi.org/10.36418/jist.v3i7.466.
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Porosity, permeability, and fluid saturation (gas, oil, water) are three important physical properties of rocks, especially in oil and gas reservoirs (oil and gas) which are carried out in core rock analysis. The purpose of this study is to determine the relationship between porosity, permeability, and oil saturation in limestone (limestone) from a horizontal plug core sample to a vertical core plug sample, to be associated with its distribution vertically and horizontally (laterally). The research method used is a Lab Test conducted at the Routine Core Analysis (RCAL) Laboratory at PPTMBG "Lemigas" Jakarta, and graphical analysis of the measurement results. The core plug samples used were 21 (twenty one) which were taken horizontally and 10 were taken vertically, which has been described, from conventional core samples from limestone reservoirs. The results of his research are that the porosity values of the vertical and horizontal samples of limestone have an indistinguishable trend, while limestones without chalky have a deeper trend, the porosity is greater, while porosity with chalky has a scatter trend, this indicates that the porosity of limestones is higher. influenced by lithological conditions or depending on the facies and the time of diagenesis, not depending on the depth (as in the case of sandstone). The value of oil saturation in the vertical and horizontal samples has a distribution that can be said to not show a certain trend or scatter. The relationship between porosity and permeability is exponentially proportional, regardless of depth and vertical or horizontal core sampling position. The value of porosity and permeability of limestone with the presence of chalky is more dominant, significantly increasing the value of porosity and permeability compared to that without the presence of chalky.
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S, Rini Rahmatia, Aang Panji Permana und Ronal Hutagalung. „POTENSI BATUGAMPING TERUMBU GORONTALO SEBAGAI BAHAN GALIAN INDUSTRI BERDASARKAN ANALISIS GEOKIMIA XRF“. EnviroScienteae 19, Nr. 2 (10.05.2023): 16. http://dx.doi.org/10.20527/es.v19i2.5469.
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Reservoir rocks are hollow rocks below the surface that are capable of storing and flowing groundwater that can be utilized by the community. The limestone facies is a good reservoir rock. The characteristics of the limestone facies in the Ombulo Region, Gorontalo Regency, which reach 3.42 km2, are very interesting to study. This study aims to analyze the porosity value of each limestone facies in the study area. The research method used consisted of field geological surveys and petrographic laboratory analysis. The results showed that the study area consisted of four limestone facies namely floatstone facies, mudstone facies, wackestone facies, and rudstone facies. The potential of limestone in the Ombulo area as reservoir rock is in the poor to very good category.
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Ali, Alyaa M., und Ayad A. Alhaleem. „Determination of Reservoir Hydraulic Flow Units and Permeability Estimation Using Flow Zone Indicator Method“. Iraqi Journal of Chemical and Petroleum Engineering 24, Nr. 2 (29.06.2023): 89–95. http://dx.doi.org/10.31699/ijcpe.2023.2.10.
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Reservoir characterization plays a crucial role in comprehending the distribution of formation properties and fluids within heterogeneous reservoirs. This knowledge is instrumental in constructing an accurate three-dimensional model of the reservoir, facilitating predictions regarding porosity, permeability, and fluid flow distribution. Among the various methods employed for reservoir characterization, the hydraulic flow unit stands out as a widely adopted approach. By effectively subdividing the reservoir into distinct zones, each characterized by unique petrophysical and geological properties, hydraulic flow units enable comprehensive reservoir analysis. The concept of the flow unit is closely tied to the flow zone indicator, a critical parameter that defines the porosity-permeability relationships of each hydraulic flow unit. Additionally, the flow zone indicator method proves valuable in estimating permeability accurately. In this study, we demonstrate the application of the flow zone indicator method to determine hydraulic flow units within the Khasib formation. By analyzing core data and calculating the Rock Quality Index (RQI) and Flow Zone Indicator (∅Z), we differentiate the formation into four hydraulic flow units based on FZI values. Specifically, HFU 1 represents a rock of poor quality, corresponding to compact and chalky limestone. HFU 2 represents intermediate quality, corresponding to argillaceous limestone, while HFU 3 represents good quality, corresponding to porous limestone. Lastly, HFU 4 signifies an excellent reservoir rock quality characterized by vuggy limestone. By establishing a permeability equation that correlates with effective porosity for each rock type, we successfully estimate permeability. Comparing these estimated permeability values with core permeability reveals a strong agreement with a high correlation coefficient of 0.96%. Consequently, the flow zone indicator method effectively classifies the Khasib formation into four distinct hydraulic flow units and provides an accurate and reliable means of determining permeability in the reservoir. The resulting permeability equations can be applied to wells and depth intervals lacking core measurements, further emphasizing the practical utility of the FZI method.
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Chopping, Curtis, und John P. Kaszuba. „Reactivity of supercritical sulfur dioxide and carbon dioxide in a carbonate reservoir: An experimental investigation of supercritical fluid-brine-rock interactions relevant to the Madison Limestone of Southwest Wyoming“. Interpretation 5, Nr. 4 (30.11.2017): SS43—SS58. http://dx.doi.org/10.1190/int-2017-0025.1.
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Managing impure carbon dioxide produced by fossil fuel-based generation of electricity is required for successful implementation of carbon capture, utilization, and storage. Impurities in carbon dioxide, particularly [Formula: see text] and [Formula: see text], are geochemically more reactive than the carbon dioxide and may adversely impact a carbon dioxide storage reservoir by generating additional acidity. Hydrothermal experiments are performed to evaluate geochemical and mineralogic effects of injecting [Formula: see text]-[Formula: see text] fluid into a carbonate reservoir. The experimental design is based on a natural carbon dioxide reservoir, the Madison Limestone on the Moxa Arch of Southwest Wyoming, which serves as a natural analog for geologic cosequestration of sulfur dioxide and carbon dioxide. Idealized Madison Limestone ([Formula: see text]) and [Formula: see text] brine ([Formula: see text], initial [Formula: see text]) reacted at reservoir conditions (110°C and 25 MPa) for approximately 165 days (3960 h). Carbon dioxide fluid containing 500 ppmv sulfur dioxide was injected and the experiment continued for approximately 55 days (1326 h). Sulfur dioxide partitions out of the supercritical carbon dioxide phase and dissolves into coexisting brine on the time scale of the experiments (55 days). Injecting supercritical [Formula: see text]-[Formula: see text] or pure supercritical carbon dioxide into a brine-limestone system produces the same in situ pH (4.6) and ex situ pH (6.4–6.5), as measured 28 h after injection because dissolution of calcite buffers in situ pH. Precipitation of anhydrite sequesters injected sulfur and, coupled with dissolution of calcite, effectively buffers the amount of dissolved calcium to the same concentrations measured in limestone-brine experiments injected with pure carbon dioxide. Supercritical [Formula: see text]-[Formula: see text] does not enhance the sequestration potential of a carbonate reservoir relative to pure supercritical carbon dioxide. Our results substantiate predictions from natural analog studies of the Madison Limestone that anhydrite traps sulfur and carbonate minerals ultimately reprecipitate and mineralize carbon in carbonate reservoirs.
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You, Donghua, Jun Han, Wenxuan Hu, Yixiong Qian, Qianglu Chen, Binbin Xi und Hongqiang Ma. „Characteristics and formation mechanisms of silicified carbonate reservoirs in well SN4 of the Tarim Basin“. Energy Exploration & Exploitation 36, Nr. 4 (19.02.2018): 820–49. http://dx.doi.org/10.1177/0144598718757515.
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High-yield natural gas was discovered in well SN4 in the Ordovician Yingshan Formation in the Tarim Basin. The gas is found in unusual, silicified, carbonate reservoirs. According to the degree of silicification, the silicified reservoirs can be divided into a lower section of silicified carbonates, a middle section of limestone, and an upper section of silicified carbonates. The silicified carbonates are mainly composed of quartz and calcite, in which the reservoir space mostly occurs as vugs, inter-crystalline pores of quartz, and partial fractures. Porosity varies widely, ranging from 3 to 20.5% with strong heterogeneity. The homogenization temperatures of fluid inclusions in quartz and calcite show that the silicification temperatures were 150–190°C, with characteristics of high temperature/low salinity and low temperature/high salinity. The 87Sr/86Sr ratios of secondary calcite are 0.709336–0.709732, which are significantly higher than that of concurrent seawater, indicating that the hydrothermal fluid originated from the deep clastic strata or the basement (sialic rock). The δ13C values of the secondary calcite are similar to that of the surrounding limestone, indicating that the carbon in the secondary calcite is derived from the limestone strata, and that the secondary calcite is the product of dissolution and re-precipitation resulting from interaction between the silica-bearing hydrothermal fluids and surrounding limestones. The silicification of silica-bearing hydrothermal fluid was significantly controlled by strike-slip faults. The fluids ascending along the fault zone and branch faults interacted with the surrounding limestone in the Yingshan Formation. As a result, a large amount of quartz and secondary calcite were formed together with various types of secondary pores, resulting in excellent reservoirs.
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Selema, S. B., R. U. Ideozu und E. J. Acra. „MID CRETACEOUS SUBSURFACE CARBONATE DEPOSIT AND RESERVOIR DEVELOPMENT OF THE MFAMOSING LIMESTONE CALABAR FLANK“. International Journal of Research -GRANTHAALAYAH 11, Nr. 5 (20.06.2023): 112–28. http://dx.doi.org/10.29121/granthaalayah.v11.i5.2023.5175.
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This research analyzed the reservoir quality of the Mfamosing Limestone with a view to classifying it as a potential reservoir rock within the Calabar Flank. Materials used in this research are processed seismic data acquired around the Calabar flank and well logs of three wells (A, B, C) drilled at different periods within the study area, core as well as mud log data. The procedure used involved prospect identification and mapping, structural and stratigraphic analysis, reservoir quality and classification of the carbonate rock in the study area. The results were analyzed and classified the Mfamosing Limestone using hydrocarbon storage capacity and deliverability potential. Wells A and B was drilled 0.8km apart and well C drilled 4.7km from well B which encountered the Mfamosing Limestone with logs indicating hydrocarbon in Well A which had a shallower sandstone lenses. The sandstone lens in Well A was tested for hydrocarbon and flowed briefly and stopped. Wells B and C were planned and drilled using Well A as reference amongst other parameters to evaluate the hydrocarbon potential of the Mfamosing Limestone. Wells B and C were found completely dry. Two conventional coring runs at depths 10,490ft-10,552.5ft and 10,552.5ft-10,614ft in Well B indicated that the cored intervals are light grey, moderate to very hard, and fossil rich limestone with no direct fluorescence. The core analysis results suggest that limestone is dry and highly indurated with no evidence of physical porosity. This suggest that the Mfamosing Limestone penetrated by all three wells though massive has no hydrocarbon storage capacity and deliverability potential typical of a reservoir rock. This research therefore suggests that the Mid Cretaceous subsurface Mfamosing Limestone is more of a mineral carbonate deposit than a hydrocarbon reservoir.
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Anggraeni, Septi, Junita Trivianty und Bambang Widarsono. „A LABORATORY STUDY TO IMPROVE ACID STIMULATION IN SANDSTONES“. Scientific Contributions Oil and Gas 29, Nr. 3 (29.03.2022): 25–33. http://dx.doi.org/10.29017/scog.29.3.1029.
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The main purpose of acidizing is to improve well productivity. Acids are useful for this reason because of their ability to dissolve undesired formation minerals and materials which may either be intrinsic in nature or be introduced into the formation during the processes of drilling, completion, and production. The effectiveness of acids in improving productivity in a particular well essentially depends on an accurate analysis of the problem and the selection of acid.Prudent judgment in acid to be used should be confirmed by laboratory tests. Apart from the analysis on the nature of the formation damage itself, acid selection should be based on study of reservoir rocks mineralogy and characteristics in general and accordingly the relevant material/minerals to be dissolved or removed. Improper diagnostics may result in inefficient, and even damaging, acidizing. Various studies have been conducted in this highlight (e.g. Crowe, 1984; Gidley, 1971; Crowe in Economides and Nolte, 1989; Daccord in Economides and Nolte, 1989; Ali, 1981; and Piot and Perthuis in Economides and Nolte, 1984).Those studies conducted in the past reveal that in comparison the success ratio of acidizing for limestone reservoir is almost 90%, whereas for sandstone reservoir the success ratio is only 30%. Undoubtedly, this disparity in success ratios is caused by the fact that appropriate acids dissolve limestones more properly due to limestones generally simpler mineral composition and by the fact that sandstones usually have more complex mineralogy hence providing less simple materials to dissolve. From this point Those studies conducted in the past reveal that in comparison the success ratio of acidizing for limestone reservoir is almost 90%, whereas for sandstone reservoir the success ratio is only 30%. Undoubtedly, this disparity in success ratios is caused by the fact that appropriate acids dissolve limestones more properly due to limestones generally simpler mineral composition and by the fact that sandstones usually have more complex mineralogy hence providing less simple materials to dissolve. From this point
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Azizi, Azlinda, Hazlina Husin, Nurul Aimi Ghazali, Muhammad Kamil Khairudin, Arina Sauki, Nur Hashimah Alias und Tengku Amran Tengku Mohd. „Nanoparticles Stabilized Carbon Dioxide Foams in Sandstone and Limestone Reservoir“. Advanced Materials Research 1119 (Juli 2015): 170–74. http://dx.doi.org/10.4028/www.scientific.net/amr.1119.170.
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The use of nanoparticles with carbon dioxide foams has been proposed for enhanced oil recovery due to their robust chemical stability in harsh environment. The experimental study was performed by using nanoparticles stabilized carbon dioxide foams to study their recovery of residual oil by varying the carbon dioxide flow rates on different core samples such as sandstone and limestone. Experimental setup was divided into two different kinds of experiments which are the injection of carbon dioxide foams and the injection of nanoparticles assisted carbon dioxide foams in both sandstone and limestone core samples. For the CO2 foam injection, it was found that limestone has higher oil recovery than sandstone rock samples with 38.67% recovery and 36.36% recovery for sandstone. With the nanoparticles assisted injection, the crude oil recovery increased to 41.82% and 45.33% for sandstone and limestone respectively. Limestone showed the higher porosity reduction at the end of experiment compared to sandstone with the porosity of 7.56% on limestone and 12.49% on sandstone respectively. This is due to the nanoparticles strongly absorbed at the limestone surfaces containing calcite component.
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Zhou, Guangzhao, Zanquan Guo, Dongjun Wu, Saihong Xue, Minjie Lin, Wantong Wang, Zihan Zhen und Qingsheng Jin. „Multi-Porous Medium Characterization Reveals Tight Oil Potential in the Shell Limestone Reservoir of the Sichuan Basin“. Processes 12, Nr. 6 (22.05.2024): 1057. http://dx.doi.org/10.3390/pr12061057.
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With the continuous deepening of oil and gas exploration and development, unconventional oil and gas resources, represented by tight oil, have become research hotspots. However, few studies have investigated tight oil potential in any systematic way in the shell limestone reservoir of the Sichuan Basin. Herein, we used thin section analysis, X-ray diffraction (XRD), high-pressure mercury intrusion, low-pressure N2 and CO2 adsorption experiments, low-field nuclear magnetic resonance (NMR), focused ion beam–scanning electron microscopy (FIB-SEM), and nano-CT to characterize multi-porous media. The reservoir space controlled by nonfabric, shell, and matrix constitutes all the reservoir space for tight oil. The interconnected porosity was mainly distributed in the range of 1% to 5% (avg. 2.12%). The effective interconnected porosity mainly ranged from 0.5% to 2.0% (avg. 1.59%). The porosity of large fractures was 0.1% to 0.5% (avg. 0.21%). The porosity of isolated pores and bound oil–water pores was 0.2% to 0.8% (avg. 0.44%). The dissolved pores adjacent to fractures, the microfractures controlled by the shell, the microfractures controlled by the matrix, the isolated pores, and the intracrystalline pores constitute five independent pore-throat systems. The development of pores and fractures in shell limestone reservoirs are coupled on the centimeter–millimeter–micron–nanometer scale. Various reservoir-permeability models show continuous distribution characteristics. These findings make an important contribution to the exploration and exploitation of tight oil in shell limestone.
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Shwani, Ayub Mohammed Ahmed, Jayran K. Qadir, Shukur A. Rahman, Ali S. Alsaqi Alsaqi und Amel K. Nooralddin. „Effect of the Deep Marin Balambo Formation on the Qamchuqa Reservoirs in Jambur Field“. Journal of Petroleum Research and Studies 14, Nr. 2 (12.06.2024): 1–16. http://dx.doi.org/10.52716/jprs.v14i2.857.
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A shallow-marine carbonate known as Qamchuqa Formation was originally discovered in northern Iraq's Qamchuqa Gorge at an outcrop section. For the present study the available conventional well logs include gamma ray, porosity logs (density, and neutron) with the resistivity logs used to achieve the depositional environment of the studied area in selected wells Ja-21, Ja-32, Ja-41, Ja-46, and Ja-18. The Aptian-Albian age include lower and upper Qamchuqa formations, respectively are considered a major reservoir in Jambur Oil field; therefore, the present study focused only on lower and upper Qamchuqa formations. Deep marine environment Balambo Formation separated the Aptian-Albian reservoir into three parts each part is different in petrophysical properties and lithology composition. Zone -1 is shoal facies including lower and upper Qamchuqa formations composed of dolomite, dolomitic limestone and limestone, this part is far from interfingers with Balambo Formation. Zone -2 is mixed facies between shoal facies and basinal facies composed of limestone, marly limestone,shaly limestone and with a few streaks of dolomitic limestone. This part includes well Ja-32, Ja-41, and Ja-46. Zone -3 basinal facies include Balambo Formation composed of limestone, shaly and marly limestone involving well Ja-18 only. These differences above caused interfingering and lateral change in both reservoir units (lower and upper Qamchuqa formations) with Balambo Formation, and both are not depicting reservoir in Zone -2 and especially in Zone -3. The current study explains well Ja-18 located on the permanent basin and well Ja-32, Ja-41, and Ja-46 located between permanent basin and neritic zone (mixed zone or slope margin); therefore, the south east of Jambur Oil field abandoned to drill in it to Cretaceous age.
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González-Gómez, Mailen, Héctor Galvis-Macareo, Mario García-González und Juan Carlos Ramírez-Arias. „Organic geochemistry, lithofacies and gas shale reservoir potential of cretaceous outcrops from Alto de los Caballeros section, Eastern Cordillera Basin – Colombia“. Boletín de Geología 44, Nr. 2 (07.07.2022): 95–108. http://dx.doi.org/10.18273/revbol.v44n2-2022004.
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Significant layers of shale are exposed in the Eastern Cordillera of Colombia. These Upper Cretaceous rocks from La Frontera and Conejo Formations in the Chécua-Lenguazaque Syncline, between Ubaté, Carmen de Carupa and Sutatausa towns, were evaluated using geochemical and petrographic analysis to determine their potential as gas shale reservoirs. This structure presents promising characteristics for developing a gas shale reservoir due to its areal extension, the existence of a thick layer of marine cretaceous sequence, and a near location to industrial areas, such as the colombian andean region. In La Frontera and Conejo Formations, the result of outcrop samples analysis indicates that some levels meet the geochemical characteristics required for the existence of potential gas shale reservoirs. One of these levels correspond to the base of La Frontera Formation, where limestones exhibit appropriated organic matter content and maturity conditions for gas shale. In addition, this limestone also presents micro-porosity associated with diagenetic processes and kerogen. The geochemical and petrographic features are similar to those found in the Barnett gas shale. The geochemical and petrographic characteristics reflected by the limestones of La Frontera Formation agree with the criteria described and evaluated internationally for unconventional gas shale reservoirs, similar to those found in the Barnett gas shale, and shows the best conditions for the development of these deposits. Nevertheless, it is necessary to evaluate other petrophysical properties, gas saturation, and effective gas permeability in reservoir condition in order to make a conclusive determination about gas shale potential.
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Troup, Alison, und Behnam Talebi. „Adavale Basin petroleum plays“. APPEA Journal 59, Nr. 2 (2019): 958. http://dx.doi.org/10.1071/aj18083.
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The Devonian Adavale Basin system is an under-explored, frontier petroleum basin in south-west Queensland. It has a confirmed petroleum system with production from the Gilmore gas field. The age, marine depositional environments and high carbonate content suggest the basin may have unconventional petroleum potential, and there has been renewed interest from industry in evaluating the basin. In support of this, the Queensland Department of Natural Resources, Mines and Energy has examined the source rock properties of the Bury Limestone and Log Creek Formation and has commissioned an update to the SEEBASE® interpretation of the region. Gas- to oil-mature source rocks are found in deep marine shales of the Log Creek Formation, with secondary potential in the shelfal Bury Limestone. The main known reservoir within the Adavale Basin is the Lissoy Sandstone, though sandstones found in other units may also have tight reservoir potential. These petroleum systems elements form several plays, including conventional clastic structural targets, carbonate plays, including possible reef targets, and salt plays associated with doming from the Boree Salt. Potential unconventional targets include tight sandstone, shale and limestone, with recent analysis of an organic-rich marl from the Bury Limestone indicating good retention properties. The overlying Cooper, Galilee and Eromanga basins also contain potential reservoirs for hydrocarbons generated in the Adavale Basin and Warrabin Trough.
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Zhang, Daofeng, Yan Liu, Guodong Dong, Baoxian Liu, Cheng Li und Xu Zeng. „Study on the Pore Structure Characterization of the Limestone Reservoir of the Taiyuan Formation in the Ordos Basin“. Energies 17, Nr. 13 (04.07.2024): 3275. http://dx.doi.org/10.3390/en17133275.
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In this paper, the limestone reservoir of the Upper Permian Taiyuan Formation in the Ordos Basin is taken as the research object. Through various analysis and testing methods, the characterization and classification evaluation of pore structure were carried out. The core porosity and pore structure characteristics were analyzed using nuclear magnetic resonance, gas measurement, and CT scanning. Based on the characteristics of the limestone reservoir, the optimal parameters of NMR testing were calibrated, the NMR testing method of limestone reservoir properties was established, and the NMR porosity of limestone was calculated. Using the core gray map obtained using CT scanning imaging technology, the three-dimensional digital core model of limestone was constructed, its pore space was extracted, and the porosity, pore fractal dimension, and tortuosity were calculated. The results show that with the thermodynamic experiment, the porosity of the sample will remain basically unchanged after 180 min, and the pressure in the sample was measured after 4 h and no air leakage was found. The T2 spectrum of saturated marlite is in the form of three peaks, two peaks, and one peak. On the whole, the p1 peak of the T2 spectrum of limestone corresponds to micropores, and most of the p2 and p3 peaks correspond to mesopores–macropores. The pore size of high porosity samples is 150–350 nm, and the micropores are well developed; the pore size of medium porosity samples is 80–150 nm, and some samples are well developed; the pore size of low porosity samples is mostly bimodal, with two peaks >> 300 nm and <<100 nm. With the increase in depth, the porosity decreases gradually, the fractal dimension decreases, and the tortuosity increases. The research results provide data support for the characterization of the pore structure of the limestone reservoir in the Taiyuan Formation of the Ordos Basin.
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Zeb, Razib Asim, Muhammad Haziq Khan, Waqas Naseem, Muhammad Awais, Hamza Zaheen und Ahtisham Khalid. „Reservoir Characterization of Eocene Carbonates of Central Indus Basin, Pakistan“. Indonesian Journal of Earth Sciences 2, Nr. 1 (27.06.2022): 64–77. http://dx.doi.org/10.52562/injoes.v2i1.359.
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The present study is based on petrophysical analysis of the Eocene Sui Main Limestone (SML) penetrated in wells of Qadirpur Gas Field, Central Indus Basin, Pakistan. The analyzed petrophysical property of SML includes shale volume, total porosity, effective porosity, water saturation, hydrocarbon saturation and net pay thickness. The result from the study shows that the Sui Main Limestone reservoir is capable of yielding appreciable hydrocarbon. The petrophysical interpretation revealed that the studied SML has productive reservoir characteristics with average (total and effective) porosity is in K-1, 15% in K-2 15% and 17% in K-3, average saturated hydrocarbon in SML is (70-100%) indicating that zones in wells are purely saturated with hydrocarbon, and average volume of shale in the zone of K-1, 23% in K2, 27% and in K-3, 25% respectively delineating clean formation. Facies modeling revealed that the studied Eocene formation consist of clean limestone, shaly limestone and shals. The isopach thickness map and stratigraphic correlation helps to understand the thickness of Sui Main Limestone in the field.
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Kandula, Neelima, Jessica McBeck, Benoît Cordonnier, Jérôme Weiss, Dag Kristian Dysthe und François Renard. „Synchrotron 4D X-Ray Imaging Reveals Strain Localization at the Onset of System-Size Failure in Porous Reservoir Rocks“. Pure and Applied Geophysics 179, Nr. 1 (17.11.2021): 325–50. http://dx.doi.org/10.1007/s00024-021-02902-z.
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AbstractUnderstanding the mechanisms of strain localization leading to brittle failure in reservoir rocks can shed light on geomechanical processes such as porosity and permeability evolution during rock deformation, induced seismicity, fracturing, and subsidence in geological reservoirs. We perform triaxial compression tests on three types of porous reservoir rocks to reveal the local deformation mechanisms that control system-size failure. We deformed cylindrical samples of Adamswiller sandstone (23% porosity), Bentheim sandstone (23% porosity), and Anstrude limestone (20% porosity), using an X-ray transparent triaxial deformation apparatus. This apparatus enables the acquisition of three-dimensional synchrotron X-ray images, under in situ stress conditions. Analysis of the tomograms provide 3D distributions of the microfractures and dilatant pores from which we calculated the evolving macroporosity. Digital volume correlation analysis reveals the dominant strain localization mechanisms by providing the incremental strain components of pairs of tomograms. In the three rock types, damage localized as a single shear band or by the formation of conjugate bands at failure. The porosity evolution closely matches the evolution of the incremental strain components of dilation, contraction, and shear. With increasing confinement, the dominant strain in the sandstones shifts from dilative strain (Bentheim sandstone) to contractive strain (Adamswiller sandstone). Our study also links the formation of compactive shear bands with porosity variations in Anstrude limestone, which is characterized by a complex pore geometry. Scanning electron microscopy images indicate that the microscale mechanisms guiding strain localization are pore collapse and grain crushing in sandstones, and pore collapse, pore-emanated fractures and cataclasis in limestones. Our dynamic X-ray microtomography data brings unique insights on the correlation between the evolutions of rock microstructure, porosity evolution, and macroscopic strain during the approach to brittle failure in reservoir rocks.
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Prahastomi, Mochammad, Achmad Fahruddin, Lauti D.Santy und Ryandi Adlan. „Depositional Facies Model and Reservoir Quality of Paleogene Limestone in Labengki Island, Southeast Sulawesi“. Jurnal Geologi dan Sumberdaya Mineral 23, Nr. 3 (31.08.2022): 189–96. http://dx.doi.org/10.33332/jgsm.geologi.v23i3.507.
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Eastern Indonesia has become an attractive venture for hydrocarbon exploration since 10 years ago. The discovery of hydrocarbon from Miocene carbonate of Tondo Formation has opened a new opportunity and hopes in the Southeast Sulawesi region. Can we find other potential reservoirs in Southeast Sulawesi? In this study, we assess and reconstruct the depositional model and the reservoir quality of the Paleogene Tampakura Formation in Labengki Island, Southeast Sulawesi. This field observation and petrographical study revealed that: (1) Tampakura Formation comprises mainly of grainstone, boundstone and floatstone with minor packstone and dolomitic wackestone/mudstone, (2) Tampakura Formation was deposited mainly in wide carbonate sand shoals and reef margin belt of rimmed carbonate shelf, (3) Boundstone and floatstone facies could be the best reservoir candidate in the region since they show extensive porosities development of cavernous and fracture porosity, (4) Dolomite cementation has deteriorated the reservoir quality of packstone which was deposited in platform interior-restricted marine, (5) Extensive calcite cementation in grainstone facies has reduced the reservoir quality of Tampakura Formation. However, locally, solution enlarged fracture porosity may have enhanced it. We suggest that post collision event of Late Oligocene - Early Miocene between Australian-originated microcontinent and ophiolite complex was highly responsible to create cavernous porosity. The collision resulted in the folding and uplifting of Tampakura Formation to the subaerial exposure. The carbonate strata were exposed to the surface developing a cavernous porosity and potentially becoming the best reservoir candidate for the next exploration target.Keywords: Carbonate facies, Kendari Basin, reservoir quality, Tampakura Formation.
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Rahman, Arief, und Rani Rahmawati. „Pengaruh Chalky pada Porositas dan Permeabilitas Reservoir Batugamping Berdasarkan Uji Laboratorium Sampel Core, dari Lapangan “AR”“. Jurnal Indonesia Sosial Teknologi 2, Nr. 6 (21.06.2021): 916–28. http://dx.doi.org/10.36418/jist.v2i6.175.
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Porositas batuan reservoir menentukan jumlah volume cadangan migas, sedangkan permeabilitas sangat penting untuk radius pengurasan migas dan recovery factor (RF). Tujuan dari penelitian yaitu mengetahui efek kedalaman terhadap porositas batugamping (limestone), hubungan porositas dan permeabilitas, dan mengetahui efek/pengaruh adanya chalk pada sampel core plug batugamping terhadap nilai porositas dan permeabilitas. Metode penelitian yang digunakan adalah Uji Lab yang dilakukan di Laborarotium Routine Core Analysis (RCAL) di PPPTMBG “Lemigas” Jakarta. Bahan yang digunakan adalah 21 (duapuluh satu) sampel core plug yang diambil secara horizontal, yang sudah dideskripsi, dan siap uji, dari sampel conventional core dari reservoir batugamping yang mengandung minyak bumi (oil reservoir), dari lapangan “AR”. Tahapan penelitian yaitu mengukur nilai porositas (ø) dan permeabilitas (k) menggunakan alat porosimeter-permeameter dengan gas helium, kemudian plot grafik hasil pengukuran, untuk dilakukan analisis. Hasilnya, pengukuran porositas limestone tanpa chalky terendah yaitu 11,58% s.d tertinggi yaitu 23,79%, atau cukup (fair) hingga sangat baik (very good), sedangkan porositas limestone dengan chalky terendah yaitu 29,20% s.d tertinggi yaitu 42,12%, atau istimewa (excellent). Permeabilitas limestone tanpa chalky terendah yaitu 0,5 mD s.d tertinggi yaitu 10,90 mD, atau ketat (tight) hingga cukup (fair), sedangkan permeabilitas limestone dengan chalky terendah yaitu 38,4 mD s.d tertinggi yaitu 193,90 mD, atau baik (good) hingga sangat baik (very good). Kesimpulan penelitian ini yaitu porositas batuan karbonat dalam kasus ini tidak terpengaruh terhadap kedalaman, hubungan porositas dan permeabilitas dalam kasus ini adalah berbanding lurus secara eksponensial, dan nilai porositas dan permeabilitas limestone dengan kehadiran chalky lebih baik dibanding limestone tanpa kehadiran chalky.
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Baouche, Rafik, Souvik Sen, Shib Sankar Ganguli und Khadidja Boutaleb. „Petrophysical and geomechanical characterization of the Late Cretaceous limestone reservoirs from the Southeastern Constantine Basin, Algeria“. Interpretation 9, Nr. 4 (28.07.2021): SH1—SH9. http://dx.doi.org/10.1190/int-2020-0249.1.
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We have characterized the petrophysical and geomechanical properties of the Late Cretaceous Turonian and Cenomanian carbonate reservoirs from the southeast Constantine Basin, northern Algeria. In general, Turonian carbonates exhibit a wide range of porosities (2%–15%) and permeabilities (0.001–10 mD), whereas the Cenomanian reservoir appears to be very tight (<6% porosity and <0.1 mD permeability). Based on their storage and hydraulic flow characteristics, these carbonates were classified into two distinct reservoir rock types (RRT): RRT-I is hosted by nano- to microporosities that displays poor reservoir qualities compared to the RRT-II, consisting of mesoporous Turonian intervals (>10% porosity and 0.5–10 mD permeability). The reservoir pore-pressure gradient is interpreted to be a little above the hydrostatic (0.51 psi/ft), whereas the minimum horizontal stress ([Formula: see text]) has a 0.72 psi/ft gradient. In situ stress analysis establishes a dominant strike-slip tectonic stress field in the basin. Shale intercalations associated with the carbonate facies are characterized by comparatively high failure pressure that can lead to wellbore failures, which may be avoided considering the recommended minimum drilling mud weight as obtained from the rock failure criterion. Extensive wellbore breakouts (C-quality) were observed in the acoustic image logs recorded in the studied reservoir intervals, inferring a mean maximum horizontal stress azimuth of 350°N. We recommend that deviated wells in the direction of the interpreted [Formula: see text] orientation (approximately east–west) using hydraulic fracturing can be useful to attain optimum wellbore stability and effective permeability enhancement. Our findings have significant implications for enhanced production within the tight carbonate reservoirs situated in a strike-slip domain.
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Alshammary, Zahraa, Amer Al-Khafaji und Fahad Al-Najm. „Characterization of the Yamama Reservoir in the Abu-Amood Oil Field, Nasiriya, Southern Iraq“. Iraqi Geological Journal 57, Nr. 1C (31.03.2024): 14–28. http://dx.doi.org/10.46717/igj.57.1c.2ms-2024-3-14.
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The Abu-Amood (Rafidain) Oilfield considered as one among five main fields of Nasiriya, with multiple oil reservoir units: Mishrif, Mauddud, Zubair, Nahr Umr, Ratawi, and Yamama formations. The current study highlights the findings of identifying and analyzing the petrophysical characterization of the carbonate Yamama reservoir units in the studied oil field in southern Iraq, in order to understand their influence on the reservoir hydrocarbon potential production of the field. A set of wirelines well logs for five wells was investigated for reservoir evaluation and reservoir unit characterization, including gamma-ray, caliper, spontaneous potential, neutron, sonic, density, and resistivity wire logs. The Didger Software utilized for converting the geophysical wireline log images to digital data, which was then transferred to Excel and IP software to determine and interpret the qualitative and quantitative interpretations values, like porosity, permeability, water saturation, hydrocarbon saturation (Sh), and total water volume. According to the gamma-ray vs. neutrons chart, three types of lithology were identified (limestone, argillaceous limestone, and shale). The Yamama Formation is primarily made of limestone, with argillaceous limestone accounting for the majority of the primary mineral components, and the neutron-density relationship chart which also shows a little gas in wells AAm1, 2, 4, and 5. Based on the results of the petrophysical characteristics interpretations of the oilfield wells, the Yamama Formation was include six units: YR-1, YR-2, YR-3, YR-4, YR-5, and YR-6, and separated by five barrier beds. The porosity ratio variety between fair to good (from 0.10 to 0.17%) in reservoir units which are the most significant reservoir units and oil-containing zones due to their good porosity and low water saturation and permeability which variety from very good to moderate in YR-1 unit. The remaining units are considered inefficient reservoir and do not hold hydrocarbons because of low porosity ratio and high-water saturation.
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Ghafur, Ala A., und Dana A. Hasan. „Petrophysical Properties of the Upper Qamchuqa Carbonate Reservoir through Well Log Evaluation in the Khabbaz Oilfield“. UKH Journal of Science and Engineering 1, Nr. 1 (27.12.2017): 72–88. http://dx.doi.org/10.25079/ukhjse.v1n1y2017.pp72-88.
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Khabbaz oilfield has a symmetrical subsurface anticline with a length of 20 km and a width of 4 km. Despite the fact that Khabbaz oilfield has a small size structure, it is known as one of the massive Oilfields in Iraq. The reservoirs of Khabbaz oilfield are produced by both Cretaceous and Tertiary rocks. The Upper Qamchuqa reservoir is the most productive reservoir of the Khabbaz oilfield with thickness ranges between 138 to 170 m. This formation is subdivided into two units, from the top is Unit A with a thickness of 67 m and from the bottom is Unit B with a thickness of 84.5 m. From a full set of log data of three wells (Kz-1, Kz-13 and Kz-14), the petrophysical properties of Khabbaz oilfield has been evaluated. The wireline log data includes gamma-ray log, sonic log, neutron log, density log and resistivity logs, both Rxo and Rt logs. This study revealed that Unit A represents the best reservoir characteristics where Unit A is subdivided into six reservoir subunits named (1-A, 2-A, 3-A, 4-A, 5-A and 6-A). They are separated by five non-reservoir subunits named 1-N, 2-N, 3-N, 4-N and 5-N. In addition to a less porous reservoir unit that is called Unit B, which has been divided into four reservoir subunits named 1-B, 2-B, 3-B and 4-B. These are separated by five non-reservoir units named 1-N, 2-N, 3-N, 4-N and 5-N. It has been recognized that both reservoir units A and B are clean formations and have minimum shale volume with high porosity in limestone and dolomite to dolomitic limestone lithology with high oil saturation and low water saturation. Based on the above reservoir characteristics it can be concluded that the reservoir units of the Khabbaz oilfield contain a massive commercial hydrocarbon accumulation.
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Rashid, Muhammad, Miao Luo, Umar Ashraf, Wakeel Hussain, Nafees Ali, Nosheen Rahman, Sartaj Hussain, Dmitriy A. Martyushev, Hung Vo Thanh und Aqsa Anees. „Reservoir Quality Prediction of Gas-Bearing Carbonate Sediments in the Qadirpur Field: Insights from Advanced Machine Learning Approaches of SOM and Cluster Analysis“. Minerals 13, Nr. 1 (24.12.2022): 29. http://dx.doi.org/10.3390/min13010029.
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The detailed reservoir characterization was examined for the Central Indus Basin (CIB), Pakistan, across Qadirpur Field Eocene rock units. Various petrophysical parameters were analyzed with the integration of various cross-plots, complex water saturation, shale volume, effective porosity, total porosity, hydrocarbon saturation, neutron porosity and sonic concepts, gas effects, and lithology. In total, 8–14% of high effective porosity and 45–62% of hydrocarbon saturation are superbly found in the reservoirs of the Eocene. The Sui Upper Limestone is one of the poorest reservoirs among all these reservoirs. However, this reservoir has few intervals of rich hydrocarbons with highly effective porosity values. The shale volume ranges from 30 to 43%. The reservoir is filled with effective and total porosities along with secondary porosities. Fracture–vuggy, chalky, and intracrystalline reservoirs are the main contributors of porosity. The reservoirs produce hydrocarbon without water and gas-emitting carbonates with an irreducible water saturation rate of 38–55%. In order to evaluate lithotypes, including axial changes in reservoir characterization, self-organizing maps, isoparametersetric maps of the petrophysical parameters, and litho-saturation cross-plots were constructed. Estimating the petrophysical parameters of gas wells and understanding reservoir prospects were both feasible with the methods employed in this study, and could be applied in the Central Indus Basin and anywhere else with comparable basins.
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Alemi, Dr Mehrdad, und Hossein Jalalifar. „Advanced Concepts in Naturally Fractured Reservoirs with Analysis of Field Data“. Indian Journal of Petroleum Engineering 2, Nr. 1 (30.05.2022): 1–5. http://dx.doi.org/10.54105/ijpe.b1912.052122.
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Dual porosity reservoir is mainly defined as fractured reservoir. The Two porosities are included for fracture and matrix, Flow in the fractures, oil storage in the matrix. Dual Permeability reservoir are those pay zones with flow in both the fracture and matrix systems. Single porosity means matrix, dual porosity means both matrix and fractures and triple porosity means matrix, fractures and vugs. The description of displacement mechanisms in fractured reservoirs can be construed as: oil expansion, gravity forces, capillary forces, balance of gravity and capillary forces, diffusion and convection. Fractures are usually found in limestone and dolomites due to solution, re-crystallization. Two categories of fractures are available such as: Open Fractures and Closed Fractures which depend mainly on circulation water and precipitation. Fractures which are closed at surface conditions may be open in reservoir conditions. Fractures related to folding axis are such as: longitudinal fractures, along the folding axis and transverse fractures, perpendicular to the folding axis and diagonal fractures, in relation with the folding axis. There are some pivotal issues and expressions in fractured reservoirs that in this paper, an approach to the advanced concepts in Naturally Fractured Reservoirs has been studied.
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Sabry, Marwan M., Mohamed I. Abdel-Fattah und MohamedMohamed K. El-Shafie. „Rock Typing and Characterization of the Late Cretaceous Abu Roash "G" Reservoirs at East Alam El-Shawish Field, Western Desert, Egypt“. International Journal of Petroleum Technology 10 (01.11.2023): 115–34. http://dx.doi.org/10.15377/2409-787x.2023.10.9.
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Rock typing and petrophysical characterization play a vital role in constructing reservoir models for petroleum exploration and development. This study focuses on evaluating the petrophysical characteristics of the Late Cretaceous Abu Roash "G" Reservoirs at the East Alam El Shawish field in Egypt's Western Desert. The study involved five vertical wells and employed various techniques and analyses to investigate the reservoir. Lithology determination utilizing well logs and core analysis helps identify the lithology types and corresponding porosity of the Abu Roash "G" reservoirs. Sandstone and limestone lithologies with varying porosity ranges were identified, along with the influence of shale on neutron porosity values. Facies analysis of the Abu Roash "G" Member identified seven lithofacies types, categorized into shallow marine and deeper marine depositional environments. The petrophysical analysis involves evaluating gamma-ray logs, porosity, permeability, flow zone indicator (FZI), and reservoir quality index (RQI) values for each lithofacies type. This analysis classifies the core samples into seven reservoir rock types (RRT1 to RRT7) based on petrophysical attributes, providing a clear classification of the Abu Roash "G" reservoir interval. RRT1, RRT2, and RRT3 exhibit the highest reservoir quality, while RRT4 and RRT5 indicate moderate reservoir quality. RRT6 and RRT7 exhibit low reservoir quality due to unfavorable petrophysical behavior. The findings of this study provide valuable insights into the Abu Roash "G" reservoir, including its lithofacies, reservoir properties, and depositional environments. This knowledge is crucial for reservoir characterization and optimizing oil production strategies in the region.
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Myzban, Adyan A., Mohanad H. Al-Jaberi und Methaq K. Al Jafar. „Microfacies Analysis and Depositional Environments of Lower Sa’adi Formation, Southern Iraq“. Iraqi Geological Journal 55, Nr. 2C (30.09.2022): 93–105. http://dx.doi.org/10.46717/igj.55.2c.8ms-2022-08-21.
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The Sa’adi Formation is a part of the late Cretaceous period in the Santonian-Campanian stage that represents a potential hydrocarbon-bearing reservoir across many oilfields in the Mesopotamian Basin, South of Iraq. The Formation was divided into two main parts as a stratigraphy sequence. It consists of chalky limestone with argillaceous limestone in the upper part and limestone with marly limestone in the lower part. The lower part is considered an important stratigraphic unit marked by petroleum shows. Thus, current research constructs the depositional environment, evaluates the reservoir, and predicts the best zones with good reservoir quality. The microfacies analysis was carried out on thirty-five thin sections to reveal the primary depositional environment, and well logs data were used to evaluate the petrophysical properties of the lower Sa’adi Formation. Four microfacies appeared related to the carbonate ramp, which identified the depositional system track from mid to inner ramp. These are; mudstone, wackestone, packstone, and grainstone. Twelve sub-microfacies were identified and interpreted in the lower Sa’adi Formation. These are pelagic lime mudstone to benthic foraminiferal-argillaceous wackestone in middle ramp experienced burial diagenesis and syngenetic diagenesis with intra-fossil pores. The results characterize the bioclast echinoderms, bivalves, and algae packstone to grainstone in inner ramp (open marine and shoal environments) experienced marine pore-water diagenesis, meteoric freshwater dissolution, and burial diagenesis. Shoal facies with open marine facies are the best favorable microfacies in the lower Sa’adi Formation. Diagenesis processes were represented by dissolution that improved the porosity and permeability with higher reservoir quality in the inner ramp; besides that, it was recognized that cementation and micritization reduced the reservoir quality in the middle ramp.
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Yang, Zeguang, Aiguo Wang, Liyong Fan, Zhanrong Ma, Xiaorong Luo, Xinghui Ning und Kun Meng. „Paragenesis and Formation Mechanism of the Dolomite-Mottled Limestone Reservoir of Ordovician Ma4 Member, Ordos Basin“. Minerals 13, Nr. 9 (06.09.2023): 1172. http://dx.doi.org/10.3390/min13091172.
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Despite the discovery of high-producing natural gas reservoirs in the low-permeability dolomite-mottled limestone (DML) reservoir of the fourth Member (Ma4) of the Majiagou Formation in the Ordos Basin, the current understanding of the processes responsible for reservoir formation are still superficial, which extremely restricts the effectiveness of deep petroleum exploration and development in the basin. Therefore, this study analyzed the paragenesis process of the DML reservoir through systematic petrographic and geochemical measurements. The DML consists of burrows and matrix. The burrows are mainly filled with dolomite with a small amount of micrite, calcite cement, and solid bitumen. The matrix mainly consists of wakestone or mudstone. The DML has experienced multiple diagenetic events, including seepage-reflux dolomitization, compaction, calcite cement CaI cementation, micrite recrystallization, dissolution, hydrocarbon charging, calcite cement CaII cementation, and dolomite progressive recrystallization. Dolomitization is critical to the DML reservoir formation. The pore created by dolomitization is the hydrocarbon-migrated pathway and storage space. Due to the difference in Mg2+-rich fluid supply, the degree of dolomitization decreases from west to east, which causes the difference in diagenetic evolution of the western and eastern parts of the study area. The high dolomitization degree led to strong anti-compaction ability in the west, contrary to the east. Thus, the reservoir quality of the west is better than the east.
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Hu, Dandan, Shu Wang, Limin Zhao, Bing He, Ruicheng Ma, Yuanbing Wu und Songhao Hu. „Application of Novel Differential Injection-production Optimization Strategy in Tight Pioclastic Limestone Reservoir“. Journal of Physics: Conference Series 2594, Nr. 1 (01.10.2023): 012020. http://dx.doi.org/10.1088/1742-6596/2594/1/012020.
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Abstract The permeability of the ultra-low permeability bioclastic limestone reservoir in Middel East A Oilfield is about 5md. The pore structure of the reservoir is in multimodal mode and has strong micro heterogeneity. The single well productivity was low and it was difficult to sustain production after the vertical well development was adopted in the early stage, and it has been gradually transformed into horizontal well pattern at the flank area. However, the reservoir pressure and production declined rapidly, and the development effect became worse. Through the combination of reservoir micro-characteristics and macro-production performance characteristics, this paper clarifies the ultra-low permeability bioclastic limestone oil displacement mechanism and remaining oil distribution law under the micro-macroscopic dual scale, and clarifies the reasonable well spacing of vertical well pattern and horizontal injection-production well pattern. Based on the differential single well performance characteristics and water injection development mechanism, the injection-production connectivity evaluation model based on rapid numerical simulation is established, the regional differential injection-production strategy is formulated, the injection-production optimization adjustment criteria are established, the establishment of effective displacement system for the reservoir is supported, and the adjustment of more than 280 producers have been carried out in 2020-2022. The daily oil production of a single well has been restored from 307 barrels/day in 2019 to 483 barrels/day in 2022, and the water cut is reduced from 27.1% to 22.1%, the reservoir pressure recovery of 496psi provides important experience guidance for the scale benefit production of such tight bioclastic limestone reservoir.
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Qasim, Um Albanian, und Dhifaf Sadeq. „Nodal Analysis of Naturally Flowing Wells in Faihaa Oil Field, Yamama Formation“. Iraqi Geological Journal 57, Nr. 1B (29.02.2024): 122–39. http://dx.doi.org/10.46717/igj.57.1b.10ms-2024-2-19.
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This study focuses on the Yamama Formation, a significant carbonate reservoir in southern Iraq that is one of the most important productive reservoirs in the region. The Formation is characterized by porous limestone interspersed with thin layers of argillaceous and tight limestone. The Yamama reservoir in the Faihaa oil field is divided mainly into four units; YA, YB, YC, and YD. YA and YB units are considered to be the most important oil-bearing subunits due to their good petrophysical properties. The main objective of the study is to determine the optimum production rates of four naturally flowing wells in the Faihaa oil field using the Inflow Performance Relationship and Vertical Lifting Performance curves. The study investigates four critical parameters; tubing size, water cut, reservoir pressure, and wellhead pressure, and their impact on well performance. The study finds that wellhead pressure is the primary determinant of well performance, and deviations from the original tubing size have adverse effects on well performance. An increase in water cut beyond the recommended threshold, coupled with a reduction in reservoir pressure, results in decreasing well performance. The study underscores the importance of careful monitoring and analysis of these parameters to sustain and enhance well performance in the Faihaa oil field, providing valuable insights for well operators and petroleum engineers. The study's findings can be used to optimize well performance and increase oil production rates, with significant implications for the petroleum industry.
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Li, Xiangwen, Jingye Li, Lei Li, Zhonghong Wan, Yonglei Liu, Peiling Ma und Ming Zhang. „Seismic Wave Field Anomaly Identification of Ultra-Deep Heterogeneous Fractured-Vuggy Reservoirs: A Case Study in Tarim Basin, China“. Applied Sciences 11, Nr. 24 (12.12.2021): 11802. http://dx.doi.org/10.3390/app112411802.
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Ultra-deep (7500–9000 m) Ordovician tight limestone heterogeneous fractured-vuggy reservoir is an important target of FuMan Oilfield in Tarim Basin. The strike-slip fault controlled reservoir is related to formation fracture and dissolution caused by geological stress. The seismic wave-field anomaly characteristics with different energy and irregular waveform are displayed in the seismic profile. Accurate identification of fractured-vuggy reservoirs wrapped in tight limestone is the direct scheme to improve production efficiency. Therefore, a new combination method flow of seismic wave-field anomaly recognition is proposed. In this process, the seismic data must be preprocessed initially, and on this basis, robust formation dip scanning is carried out. Secondly, the dip data is applied to the transverse smoothing filter to obtain the formation background data. Eventually, the seismic wave-field anomaly data is the residual between background data and original seismic data. This method has been applied in blocks with different structural characteristics and can effectively improve the resolution of strike-slip fault controlled reservoirs. Based on the results, the drilling success rate is increased to more than 95%, and the high-yield rate of oil tests is increased to 75% in 2021. Multiple applications indicate that the method is robust and can be popularized.
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Vandenberghe, Noël, Michiel Dusar, Paul Boonen, LIE Sun Fan, Rudy Voets und Jos Bouckaert. „The Merksplas-Beerse geothermal well (17W265) and the Dinantian reservoir“. Geologica Belgica 3, Nr. 3-4 (01.10.2001): 349–67. http://dx.doi.org/10.20341/gb.2014.037.
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The Merksplas-Beerse well (North Belgium) is a low-enthalpy geothermal production well targeting the Dinantian karstic limestones to a total depth of 1761 m. The presence of methane gas in these limestones generated a particular interest in this well. This paper describes the geological profile of this well and the Dinantian reservoir. The Namurian-Visean boundary at 1630 m is determined by the base of the dipmeter draping pattern in the radioactive Chokier shales (base of the Namurian) on top of the karstified Dinantian limestone. The stratigraphic composition of the transitional interval from Dinantian to Silesian correlates closely to the nearby Turnhout well. The two fractured intervals at 1630-1656 and 1739-1747 m respectively were identified in the Dinantian limestones. They are associated with siliciclastic sections in between pure limestones. The reservoir water is a sodium chloride brine of about 74 °C and at a pressure below the hydrostatic. The water is slightly radioactive because of the contact with the Chokier hot shales. A carbon dioxide gas with methane and nitrogen admixture is dissolved in the water. The gas liquid ratio at standard conditions is about one and the bubble point is around 200-400 psi at reservoir temperature. A long duration pumping test shows a high fracture permeability and a productivity index of 5.4 m3/h/bar with a productivity to injectivity ratio of 1.45.
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Coelho, Lúcia Carvalho, Antonio Claudio Soares, Nelson Francisco F. Ebecken, José Luis Drummond Alves und Luiz Landau. „Modelling mechanical behaviour of limestone under reservoir conditions“. International Journal for Numerical and Analytical Methods in Geomechanics 30, Nr. 14 (2006): 1477–500. http://dx.doi.org/10.1002/nag.543.
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