Academic literature on the topic 'Limestone reservoir'
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Journal articles on the topic "Limestone reservoir"
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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, no. 01 (November 20, 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, and 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, no. 5 (March 1, 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., and J. M. Davies. "UPPER PERMIAN CARBONATE RESERVOIRS OF THE NORTH WEST SHELF AND NORTHERN PERTH BASIN, AUSTRALIA." APPEA Journal 39, no. 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, and Sunarty Suly Eraku. "Kualitas Batugamping Gorontalo Sebagai Reservoir Air Tanah Berdasarkan Analisis Jenis Porositas." EnviroScienteae 16, no. 1 (August 18, 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, and Zhao Yuanyuan. "Lacustrine Carbonate Reservoir Characteristics Research of Jurassic Da’anzhai Member in North Central Sichuan Basin." Open Petroleum Engineering Journal 8, no. 1 (September 10, 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, and Zengye Xie. "Mechanisms by Which an Evaporated Lagoon Sedimentation System Controls Source–Reservoir Preservation in Lei32 Sub-Member Unconventional Oil and Gas." Energies 17, no. 4 (February 19, 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, and 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, no. 2 (June 24, 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, no. 1 (February 14, 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, no. 2 (April 1, 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, no. 2D (October 31, 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.
Dissertations / Theses on the topic "Limestone reservoir"
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García, Ríos María. "Dissolved CO2 effect on the reactivity of the Hontomín reservoir rocks (limestone and sandstone)." Doctoral thesis, Universitat Politècnica de Catalunya, 2015. http://hdl.handle.net/10803/287988.
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A test site for CO2 geological storage is situated in Hontomín (Burgos, northern Spain) with a reservoir rock that is mainly composed of limestone (80-85%) and sandstone (15-20%). The reservoir rock is a deep saline aquifer that is covered by a very low permeability formation which acts as a cap rock. During and after CO2 injection, since the resident groundwater contains sulfate, the resulting CO2-rich acid solution gives rise to the dissolution of carbonate minerals (calcite and dolomite) and secondary sulfate-rich mineral precipitation (gypsum or anhydrite) may occur. These reactions that may imply changes in the porosity, permeability and pore structure of the repository could vary the CO2 storage capacity and injectivity of the reservoir rock.
Therefore, better knowledge about the overall process of gypsum precipitation at the expense of carbonate mineral dissolution in CO2-rich solutions and its implications for the hydrodynamic properties of the reservoir rocks is necessary. A first aim of this thesis is to better understand these coupled reactions by assessing the effect that P, pCO2, T, mineralogy, acidity and solution saturation state exert on these reactions. To this end, experiments using columns filled with crushed limestone or dolostone are conducted under different P-pCO2 conditions (atmospheric:1-10-3.5 bar; subcritical: 10-10 bar; and supercritical: 150-34 bar), T (25, 40 and 60 °C) and input solution compositions (gypsum-undersaturated and gypsum-equilibrated solutions). The CrunchFlow and PhreeqC (v.3) numerical codes are used to perform 1D reactive transport simulations of the experiments to evaluate mineral reaction rates in the system and quantify the porosity variation along the column.
Within the range of P-pCO2 and T of this study only gypsum precipitation takes place and this only occurs when the injected solution is equilibrated with gypsum. Under the P-pCO2-T conditions, the volume of precipitated gypsum is smaller than the volume of dissolved carbonate minerals, yielding always an increase in porosity (¿¿ up to ¿ 4%).
A decrease in T favors limestone dissolution regardless of pCO2 owing to increasing undersaturation with decreasing temperature. However, gypsum precipitation is favored at high T and under atmospheric pCO2 conditions but not at high T and under 10 bar of pCO2 conditions. The increase in limestone dissolution with pCO2 is directly attributed to pH, which is more acidic at higher pCO2.
A decrease in T favors limestone dissolution regardless of pCO2 owing to increasing undersaturation with decreasing temperature. However, gypsum precipitation is favored at high T and under atmospheric pCO2 conditions but not at high T and under 10 bar of pCO2 conditions. The increase in limestone dissolution with pCO2 is directly attributed to pH, which is more acidic at higher pCO2.
Limestone dissolution induces late gypsum precipitation (long induction time) in contrast to dolostone dissolution, which promotes rapid gypsum precipitation. Moreover, owing to the slow kinetics of dolomite dissolution with respect to that of calcite, both the volume of dissolved mineral and the increase in porosity are larger in the limestone experiments than in the dolostone ones under all pCO2 conditions (10-3.5 and 10 bar).
Limestone dissolution induces late gypsum precipitation (long induction time) in contrast to dolostone dissolution, which promotes rapid gypsum precipitation. Moreover, owing to the slow kinetics of dolomite dissolution with respect to that of calcite, both the volume of dissolved mineral and the increase in porosity are larger in the limestone experiments than in the dolostone ones under all pCO2 conditions (10-3.5 and 10 bar).Una planta pilot per a l'emmagatzematge geològic de CO2 es troba a Hontomín (Burgos). El reservori és un aqüífer salí profund, format principalment per roca calcària (80-85%) i gres (15-20%), que està situat entre dues capes de molt baixa permeabilitat que actuen com a roques segell. La dissolució de CO2 a l'aigua del reservori provocarà una disminució del pH i, en conseqüència, la dissolució dels carbonats presents en el reservori. Tenint en compte que l'aigua resident és rica en sulfat, és possible la precipitació de minerals secundaris (guix o anhidrita). Aquestes reaccions poden provocar canvis en la porositat, la permeabilitat i l'estructura de por del reservori que, a la vegada, poden afectar la seva injectivitat i capacitat d'emmagatzematge. Per tant, cal aprofundir en el coneixement sobre els processos acoblats de precipitació de guix i dissolució de carbonats (calcita i dolomita) en solucions riques en CO2 dissolt i les seves implicacions en les propietats hidrodinàmiques de la roca reservori. Un primer objectiu d'aquesta tesi és poder comprendre millor aquestes reaccions acoblades mitjançant l'avaluació de l'efecte que exerceixen la pressió P, la pressió parcial de CO2 pCO2, la temperatura T, la mineralogia, l'acidesa i l'estat de saturació de la solució sobre aquestes reaccions. Amb aquest objectiu, s'han realitzat una sèrie d'experiments utilitzant columnes plenes de roca calcària o dolomia triturada sota diferents condicions de P-pCO2 (atmosfèrica: 1-10-3.5 bar; subcrítica: 10-10 bar, i supercrítica: 150-34 bar), T (25, 40 i 60 ° C) i composició de la solució d'entrada (solucions subsaturades o equilibrades amb guix). Els codis numèrics CrunchFlow i PhreeqC (v.3) s'han utilitzat per realitzar simulacions de transport reactiu dels experiments en columna amb l'objectiu d'avaluar les velocitats de reacció en el sistema i quantificar la variació de la porositat al llarg de la columna. En les condicions de P-pCO2-T estudiades, la precipitació de guix únicament té lloc quan la solució injectada està en equilibri amb guix. A més, el volum de guix precipitat és menor que el volum de carbonat dissolt, originant sempre un augment de porositat. Una disminució en la T afavoreix la dissolució de la calcària independentment de la pCO2 degut a l'augment de la subsaturació. No obstant, la precipitació de guix està afavorida a alta T per condicions atmosfèriques, originant-se l¿efecte contrari per condicions subcrítiques. L'augment de la pCO2 comporta un augment en la dissolució de calcària, fet que és directament atribuït a l'efecte del pH, que és més àcid a major pCO2. La dissolució de calcària comporta un retard en la precipitació de guix (llarg temps d'inducció), al contrari del que passa amb la dissolució de dolomia que promou una ràpida precipitació de guix. A més, a causa de la lenta cinètica de dissolució de la dolomita amb respecte a la de la calcita, el volum de mineral dissolt i l'augment de porositat són majors en els experiments amb calcària sota totes les condicions de pCO2 estudiades. La dissolució de calcària comporta un retard en la precipitació de guix (llarg temps d'inducció), al contrari del que passa amb la dissolució de dolomia que promou una ràpida precipitació de guix. A més, a causa de la lenta cinètica de dissolució de la dolomita amb respecte a la de la calcita, el volum de mineral dissolt i l'augment de porositat són majors en els experiments amb calcària sota totes les condicions de pCO2 estudiades. La dissolució del carbonat es produeix al llarg de tota la columna quan la pCO2 és alta (10 and 34 bar) i, en canvi, es localitza a l'entrada de la columna sota condicions atmosfèriques. Aquesta diferència és deguda a la capacitat tampó de l'àcid carbònic, ja que manté el pH al voltant de 5 i la solució subsaturada pel que fa a la calcita i a la dolomita al llarg de la columna
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Jensik, Chandler. "Geologic controls on reservoir quality of the Viola limestone in Soldier Field, Jackson County, Kansas." Thesis, Kansas State University, 2013. http://hdl.handle.net/2097/16902.
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Master of ScienceDepartment of Geology
Matthew Totten
Jackson County, Kansas is situated on the west side of the Forest City Basin, location of the first oil discovery west of the Mississippi River (KGS), Production in the area is predominately from the Viola Limestone, and a noticeable trend of oil fields has developed where the basin meets the Nemaha Anticline. Exploration has been sluggish, because of the lack of an exploration model. Production rates have varied widely from well to well, even when they are structurally equivalent. The goal of this study was to determine the factors controlling reservoir quality in the Ordovician-aged Viola Limestone so that a better exploration model could be developed. A two township area was studied to examine relationships between subsurface variations and production rates. In the absence of an available core through the Viola, drill cuttings were thin-sectioned and examined under a petrographic microscope to see the finer details of porosity, porosity type and dolomite crystal-size that are not visible under a binocular microscope. Production appears to be controlled by a combination of structural position and dolomite crystal size, which was controlled by secondary diagenesis in the freshwater-marine phreatic mixing zone. The best wells exhibited a Viola Limestone made up of 100% very coarsely crystalline, euhedral dolomite crystals. These wells occur on the east and southeast sides of present day anticlines, which I have interpreted to be paleo-highs that have been tilted to the east-southeast.
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McIlwain, Jason Andrew. "Hydrogeologic assessment of a proposed reservoir site, Smith County, Mississippi." Master's thesis, Mississippi State : Mississippi State University, 2007. http://library.msstate.edu/etd/show.asp?etd=etd-02282008-134137.
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Powell, Kristopher Michael. "Facies Analysis, Sedimentary Petrology, and Reservoir Characterization of the Lower Triassic Sinbad Limestone Member of the Moenkopi Formation, Central Utah: A Synthesis of Surface and Subsurface Data." BYU ScholarsArchive, 2017. https://scholarsarchive.byu.edu/etd/6672.
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Lower Triassic strata in the Wellington Flat and Tully cores reflect a lateral transition from shallow water strata (Wellington Flats core) to strata that indicate deposition on a relatively more distal, storm-dominated ramp (Tully core). The Sinbad Member, along with the upper part of the underlying Black Dragon Member and the lower part of the overlying Torrey Member (Moenkopi Formation), are composed of ten carbonate, siliciclastic and mixed carbonate/siliciclastic facies deposited on a west-facing ramp/shelf that reached maximum flooding during Smithian time. Individual beds and facies display a large degree of lateral homogeneity and regional persistence in the study area. The Wellington Flats core contains the three units characteristic of outcropping Sinbad Limestone: a basal skeletal unit, a middle peloidal unit, and an upper, oolitic dolomite unit. The more offshore Tully core is composed of skeletal grainstone, with fewer shallow-water carbonate and siliciclastic deposits. Discontinuity surfaces (hardgrounds, firmgrounds, and change surfaces) are common and indicate that sedimentation was punctuated by short-lived hiatuses accompanied by cementation, scour, and/or encrustation of the sediment-water interface. The Black Dragon, Sinbad, and lower Torrey Members represent at least one 3rd-order depositional sequence bounded below by the Tr-1 unconformity and above by lowstand deposits in the middle Torrey Member. Amalgamated fluvial channels in the middle of the Black Dragon Member may represent an additional 3rd-order sequence boundary that separates a Greisbachian sequence (lower Black Dragon Member) from the Smithian sequence (upper Black Dragon through lower Torrey members), but this is unsubstantiated by biostratigraphic data at present. Diagenesis is strongly controlled by facies. Diagenetic elements include marine fibrous calcite cements, micritized grains, compaction, dissolution and neomorphism of aragonite grains, meteoric cements, pressure dissolution, and dolomitization. The paragenetic sequence progresses from marine to meteoric to burial. Marine and meteoric cements occlude much of the depositional porosity, which ranges from 0 to 10 % in the sample interval. The best reservoir qualities in core (1.0 md) occur in grainstones and quartz-siltstones. Although its relative thinness precludes it from being a major producer, the Sinbad Limestone Member of the Moenkopi Formation bears potential for modest future oil production.
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Flenthrope, Christopher. "Developing an exploration model by investigating the geological controls on reservoir production within the Fort Scott limestone, Ness county, Kansas." Thesis, Manhattan, Kan. : Kansas State University, 2009. http://hdl.handle.net/2097/1388.
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Osborn, Caleb R. "Microfacies Analysis, Sedimentary Petrology, and Reservoir Characterization of the Sinbad Limestone Based Upon Surface Exposures in the San Rafael Swell, Utah." BYU ScholarsArchive, 2007. https://scholarsarchive.byu.edu/etd/1414.
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The Lower Triassic Sinbad Limestone Member of the Moenkopi Formation has produced minor amounts of oil in the Grassy Trail Creek field near Green River, Utah and is present below much of central Utah including the recently discovered Covenant field. Superb outcrops of this thin (15 m), mixed carbonate-silicilastic unit in the San Rafael Swell permit detailed analysis of its vertical and lateral reservoir heterogeneity. Vertically, the Sinbad Limestone comprises three facies associations: (A) a basal storm-dominated, well-circulated skeletal-oolitic-peloidal limestone association, (B) a storm-dominated, poorly-circulated hummocky cross-stratified siliciclastic/peloidal association, and (C) a capping peritidal cross-bedded oolitic dolograinstone association. Eleven microfacies are present in 14 measured sections within the Sinbad Limestone. Lateral variation is most pronounced in the upper part of the basal limestone where storm-deposited beds pinch out over a lateral distance of one kilometer. Otherwise, individual beds and microfacies display a large degree of lateral homogeneity and regional persistence. Diagenesis is strongly controlled by microfacies. Diagenetic elements include marine fibrous calcite cements, micritized grains, compaction, dissolution and neomorphism of aragonite grains, meteoric cements, pressure dissolution, and dolomitization. The paragenetic sequence progresses from marine to meteoric to burial. Marine and meteoric cements occlude much of the depositional porosity. Hydrocarbon-lined interparticle and separate vug (largely molds) pores (1-5%) characterize the skeletal-oolitic limestones with permeability ranging from 0-100 md. Low permeability/porosity characterizes the middle silicilastic unit. The best reservoir qualities (permeability 400 md) occur in portions of the dolomitized oolitic grainstones that form the upper 2 to 3 m of the Sinbad Limestone. Fracture analysis of the studied area indicates a strong NW-SE trend. Fracture spacing is associated with lithology. Fracturing of limestone possibly displays a higher dependence upon bed thickness and microfacies type. The degree of dolomitization controls and increases fracture spacing while siltstones display more closely spaced fractures. The basal limestone unit is an oil storage unit, medial siltstones are flow baffles/barriers, and the dolostone caprock is an oil flow unit. If good connectivity through fractures can be obtained between the dolostone and limestone units, the Sinbad Limestone has potential to serve as a reservoir. This study will not only aid in future Sinbad exploration, but will serve as a model for parasequence-scale intervals in thicker mixed carbonate-siliciclastic successions.
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Vohs, Andrew B. "3D seismic attributes analysis in reservoir characterization: the Morrison NE field & Morrison field, Clark County Kansas." Thesis, Kansas State University, 2015. http://hdl.handle.net/2097/20600.
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Master of ScienceDepartment of Geology
Abdelmoneam Raef
Seismic reservoir characterization and prospect evaluation based 3D seismic attributes analysis in Kansas has been successful in contributing to the tasks of building static and dynamic reservoir models and in identifying commercial hydrocarbon prospects. In some areas, reservoir heterogeneities introduce challenges, resulting in some wells with poor economics. Analysis of seismic attributes gives insight into hydrocarbon presence, fluid movement (in time lapse mode), porosity, and other factors used in evaluating reservoir potential. This study evaluates a producing lease using seismic attributes analysis of an area covered by a 2010 3D seismic survey in the Morrison Northeast field and Morrison field of Clark County, KS. The target horizon is the Viola Limestone, which continues to produce from seven of twelve wells completed within the survey area. In order to understand reservoir heterogeneities, hydrocarbon entrapment settings and the implications for future development plans, a seismic attributes extraction and analysis, guided with geophysical well-logs, was conducted with emphasis on instantaneous attributes and amplitude anomalies. Investigations into tuning effects were conducted in light of amplitude anomalies to gain insight into what seismic results led to the completion of the twelve wells in the area drilled based on the seismic survey results. Further analysis was conducted to determine if the unsuccessful wells completed could have been avoided. Finally the study attempts to present a set of 3D seismic attributes associated with the successful wells, which will assist in placing new wells in other locations within the two fields, as well as promote a consistent understanding of entrapment controls in this field.
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Paipe, Félix António Guimarães. "Masters Thesis Effect of Brine Concentration on Flow Properties in Two Types of Carbonate Rocks Ekofisk Chalk and Iranian Limestone : Study of Chemical Effect of Brine Composition on Flow Properties on Carbonate Rocks." Thesis, Norges teknisk-naturvitenskapelige universitet, Institutt for petroleumsteknologi og anvendt geofysikk, 2012. http://urn.kb.se/resolve?urn=urn:nbn:no:ntnu:diva-19269.
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SummaryThe displacement of oil from reservoir rock pore spaces is a function of many interacting variables, amongst which the reservoir wetting state has been shown to be one of the important affected by the rock lithology, oil chemistry and brine salinity. A finding from previous research says that the injection brine into oil saturated core plug increased oil recovery. Based on this the objective of this master thesis is to investigate the effect of brine concentration on flow properties in two types of carbonate rocks for enhanced oil recovery (EOR) through imbibition and water flooding processes.The methodology used to evaluate the effect of brine concentration (BC) and chemical composition (CC) for oil recovery consisted on two stages. The first stage covers the literature review regarding the effect of brine concentration and chemical composition, including carbonates (chalk and limestone) characteristics. The second stage is related to the laboratory experiment which was performed using n-Decane oil, six (6) brines with different concentrations and chemical composition and the six (6) core plugs where four (4) “chalks” from Ekofisk (Norway) and the other two (2) “limestones” from Iranian field. The experiment was carried out in the laboratory of Institute of Petroleum and Technology (IPT), the materials, chemicals products, apparatus and equipments, methodology and procedures were provided by the IPT laboratory.To carry out the laboratory experiments, initially the two cores from Iranian were cleaned before being used. Different properties of brines, cores and oil were measured using different methods and procedures; and results were computed. Next, each core was saturated with one type of brine and after that flooded by n-Decane oil for establishment of initial water saturation and determination of volume of oil produced by drainage process at room temperature conditions at one bar. After that, all cores were aging about 15 days at room temperature condition. Finally, each core was flooded using brine by imbibition process at room temperature conditions.Results achieved were computed and discussed based on the literature review and compared with “A salinity (AS) Ekofisk core reference case” and similar studies. From this study was observed that the matrix block has a high porosity. The average porosity was about 40.24% of the volumes of large pores. The average absolute permeability was about 3.73 mD which is low because the microporous dominate the pore network. The average brine density (ρ) was about1.026 g/cm3 and pH was about 7.25. The initial water saturation varies between 14.58 to 28.50% and residual oil saturation among 22.49 to 62%. The sleeve pressure in the cylinder was kept from 15 to 28 bar. During waterfloodig was observed that the breakthrough pressure drop and time to increases when the oil recovery increase.The highest original oil in place (OOIP) was achieved in the low salinity (LS) core which was about 68.46% and the lowest was recorded in the C salinity (CS) core which was around 26.71%. The reason of the high and the low recovery is related with the effect of brine concentration and chemical composition of Sodium, Calcium, Magnesium and Sulphate, added in the solution. The main driving mechanism for low salinity waterflooding is believed to be multi component ionic exchange made possible by the expansion of electrical double layer. The permeability and porosity of the cores can be pointed as other factor. In general, it was showen that there is an increase in oil recovery as the salinity decreases.
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Söderberg, Felix. "Petrophysical and GeophysicalAnalysis of Ordovician Limestone Mounds for the Purpose of Hydrocarbon Reservoir Exploration : Petrofysisk och geofysisk analys av Ordoviciska kalkstensstrukturer för hydrokarbonprospektering." Thesis, Uppsala universitet, Institutionen för geovetenskaper, 2015. http://urn.kb.se/resolve?urn=urn:nbn:se:uu:diva-259706.
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Gripen Oil & Gas have extended their prospecting license on Gotland to the north end of the island to search for potential hydrocarbon reservoirs. Earlier prospecting has shown that limestone mound structures from Ordovicium have high potential as hydrocarbon reservoirs due to their antiformal shape and the petrophysical properties of the limestone.This study focuses on the petrophysical properties of the intramound lithofacies of the Ordovician mound structures. Analyses are made to determine the density, porosity and ultrasonic velocity of ten drill core samples (both in dry and water-filled state) from different places on Gotland and these factors are compared to see how they affect one another. Seismic reflection data gathered by OPAB (provided by SGU) is also used to locate potential mound structures in northern Gotland.The results show a clear connection between the density and porosity. Increasing porosities also decreases the ultrasonic velocities of the rocks. The saturated samples show higher velocities for the compressional waves than in the dry samples, but the shear wave velocity is similar in both dry and saturated rocks. Acoustic impedance is used to link the petrophysical analysis to the geophysical data by explaining why one reflector can be seen more clearly than others in a seismic section. Using the seismic sections, five possible mounds are found on northern Gotland. Good correlations are found in the petrophysical analyses, but the porosity of the rock does not seem to be the deciding factor in choosing a reservoir. There is no association between a rock’s measured porosity and its potential extraction volume, clearly shown by the low porosity measured in the Risungs drill cores compared to how much volume of oil that has been extracted. Instead, one should look closer at the seismic sections to find mounds with a high degree of fracturing. None of the mounds seen in the seismic sections show any apparent fracturing, and more seismic surveys should be made before deciding where to drill.
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Krehel, Austin. "Investigation of time-lapse 4D seismic tuning and spectral responses to CO₂-EOR for enhanced characterization and monitoring of a thin carbonate reservoir." Thesis, Kansas State University, 2016. http://hdl.handle.net/2097/34628.
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Master of ScienceDepartment of Geology
Abdelmoneam Raef
Advancements, applications, and success of time-lapse (4D) seismic monitoring of carbonate reservoirs is limited by these systems’ inherent heterogeneity and low compressibility relative to siliciclastic systems. To contribute to the advancement of 4D seismic monitoring in carbonates, an investigation of amplitude envelope across frequency sub-bands was conducted on a high-resolution 4D seismic data set acquired in fine temporal intervals between a baseline and eight monitor surveys to track CO₂-EOR from 2003-2005 in the Hall-Gurney Field, Kansas. The shallow (approximately 900 m) Plattsburg ‘C Zone’ target reservoir is an oomoldic limestone within the Lansing-Kansas City (LKC) supergroup – deposited as a sequence of high-frequency, stacked cyclothems. The LKC reservoir fluctuates around thin-bed thickness within the well pattern region and is susceptible to amplitude tuning effects, in which CO₂ replacement of initial reservoir fluid generates a complex tuning phenomena with reduction and brightening of amplitude at reservoir thickness above and below thin-bed thickness, respectively. A thorough analysis of horizon snapping criteria and parameters was conducted to understand the sensitivity of these autonomous operations and produce a robust horizon tracking workflow to extend the Baseline Survey horizon data to subsequent Monitor Surveys. This 4D seismic horizon tracking workflow expedited the horizon tracking process across monitor surveys, while following a quantitative, repeatable approach in tracking the LKC and maintaining geologic integrity despite low signal-to-noise ratio (SNR) data and misties between surveys. Analysis of amplitude envelope data across frequency sub-bands (30-80 Hz) following spectral decomposition identified geometric features of multiple LKC shoal bodies at the reservoir interval. In corroboration with prior geologic interpretation, shoal boundaries, zones of overlap between stacked shoals, thickness variation, and lateral changes in lithofacies were delineated in the Baseline Survey, which enhanced detail of these features’ extent beyond capacity offered from well log data. Lineaments dominated by low-frequency anomalies within regions of adjacent shoals’ boundaries suggest thicker zones of potential shoal overlap. Analysis of frequency band-to-band analysis reveals relative thickness variation. Spectral decomposition of the amplitude envelope was analyzed between the Baseline and Monitor Surveys to identify spectral and tuning changes to monitor CO₂ migration. Ambiguity of CO₂ effects on tuning phenomena was observed in zones of known CO₂ fluid replacement. A series of lineaments highlighted by amplitude brightening from the Baseline to Monitor Surveys is observed, which compete with a more spatially extensive effect of subtle amplitude dimming. These lineaments are suggestive of features below tuning thickness, such as stratigraphic structures of shoals, fractures, and/or thin shoal edges, which are highlighted by an increased apparent thickness and onset of tuning from CO₂. Detailed analysis of these 4D seismic data across frequency sub-bands provide enhanced interpretation of shoal geometry, position, and overlap; identification of lateral changes in lithofacies suggestive of barriers and conduits; insight into relative thickness variation; and the ability of CO₂ tuning ambiguity to highlight zones below tuning thickness and improve reservoir characterization. These results suggest improved efficiency of CO₂ -EOR reservoir surveillance in carbonates, with implications to ensure optimal field planning and flood performance for analogous targets.
Books on the topic "Limestone reservoir"
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Zakaria, Lasemi, and Illinois State Geological Survey, eds. Waulsortian mounds and reservoir potential of the Ullin Limestone ("Warsaw") in southern Illinois and adjacent areas in Kentucky. Champaign, Ill: Dept. of Energy and Natural Resources, 1994.
Find full textBook chapters on the topic "Limestone reservoir"
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Wang, Jie, Yintao Cai, Shao-hua Hu, De-sheng Sun, Xiao-min Zhang, and Wen-tao Zhao. "Remaining Oil Prediction of Limestone Reservoir in Qaidam Basin." In Proceedings of the International Field Exploration and Development Conference 2021, 2798–804. Singapore: Springer Nature Singapore, 2022. http://dx.doi.org/10.1007/978-981-19-2149-0_259.
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Tian, Zhong-yuan, Rui Guo, Zhen-yong Xu, and Li-ping Yi. "Quantitative Petrophysical Characterization of Original Super-Permeability Zones of Bioclastic Limestone Reservoir." In Springer Series in Geomechanics and Geoengineering, 497–513. Singapore: Springer Singapore, 2018. http://dx.doi.org/10.1007/978-981-10-7560-5_45.
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Zhang, Xiao-lin, Ya-hui Wang, Wei Xu, and Xiao-long Tang. "Research on Water Flooding Mechanism and Development Strategy of Fractured Reef Limestone Reservoir." In Proceedings of the International Field Exploration and Development Conference 2021, 1118–28. Singapore: Springer Nature Singapore, 2022. http://dx.doi.org/10.1007/978-981-19-2149-0_101.
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Yu, Yi-chang, Rui Guo, Yi Shen, Bo-heng Shen, Ye Zhang, and Feng-feng Li. "Orders of Sequence Boundaries and Its Control on Diagenesis of Bioclastic Limestone Reservoir." In Proceedings of the International Field Exploration and Development Conference 2021, 4680–94. Singapore: Springer Nature Singapore, 2022. http://dx.doi.org/10.1007/978-981-19-2149-0_436.
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Fu, Xun-xun, Wei-bo Zhao, Xiao-peng Liu, Yani Jia, and Yan Liu. "Controlling Effects of Paleogeomorphy on Limestone Gas Reservoir of Marine–continent Transitional Facies." In Springer Series in Geomechanics and Geoengineering, 1568–75. Singapore: Springer Singapore, 2021. http://dx.doi.org/10.1007/978-981-16-0761-5_147.
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Wang, Gen-jiu, Xiang Xin, and Xu Jie. "Quantitative Characterization of Rock Type of Pore Type Bioclastic Limestone Reservoir in Middle East." In Springer Series in Geomechanics and Geoengineering, 2579–90. Singapore: Springer Singapore, 2021. http://dx.doi.org/10.1007/978-981-16-0761-5_241.
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Liu, Yu-mei, Yong Li, and Wei-jun Wang. "Characterization of Barrier and Interlayer in Thick Bioclastic Limestone Reservoir in a Oilfield, Middle East." In Proceedings of the International Field Exploration and Development Conference 2021, 275–84. Singapore: Springer Nature Singapore, 2022. http://dx.doi.org/10.1007/978-981-19-2149-0_24.
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Yu, Yi-chang, Rui Guo, Bo-heng Shen, Yi Shen, Ye Zhang, and Feng-feng Li. "Dynamic-Static Integrated Classification Evaluation and Distribution Based on Genetic Control of Bioclastic Limestone Reservoir." In Proceedings of the International Field Exploration and Development Conference 2021, 4665–79. Singapore: Springer Nature Singapore, 2022. http://dx.doi.org/10.1007/978-981-19-2149-0_435.
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Zhao, Wei-bo, Xun-xun Fu, Kang-le Wang, Ying Wu, Guo-Dong Dong, and Xiao-hui Zhao. "Geological Characteristics Analysis of the Taiyuan Limestone Gas Reservoir in Zizhou-Qingjian Area, Ordos Basin." In Springer Series in Geomechanics and Geoengineering, 249–58. Singapore: Springer Nature Singapore, 2024. http://dx.doi.org/10.1007/978-981-97-0464-4_21.
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Su, Weidong, Weishi Zheng, XianPeng Dong, Yang Xu, Wenxue Jiang, Xiaoqing Wang, and Yuerong Wu. "The Study on the Well Dormancy Happened in the Majiagou Limestone Reservoir in Sulige Oilfield." In Springer Series in Geomechanics and Geoengineering, 928–35. Singapore: Springer Nature Singapore, 2024. http://dx.doi.org/10.1007/978-981-97-0256-5_79.
Full textConference papers on the topic "Limestone reservoir"
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Al-Aruri, A. D., and P. R. Sarkar. "Limestone Reservoir Development: A Simulation Approach." In Middle East Oil Show. Society of Petroleum Engineers, 1987. http://dx.doi.org/10.2118/15703-ms.
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Galvis-Silva, H., and E. R. Okoroafor. "Evaluating Carbonate Reservoir Rocks for Underground Hydrogen Storage: A Comprehensive Laboratory Approach." In SPE Annual Technical Conference and Exhibition. SPE, 2024. http://dx.doi.org/10.2118/220971-ms.
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Abstract Underground Hydrogen Storage (UHS) in porous media represents a promising solution for long-term, large-scale energy storage. Despite its potential, UHS development faces challenges such as low storage efficiencies and potential geochemical reactions between hydrogen and reservoir rocks. This study investigates the behavior and interactions of carbonate rocks, specifically limestones, under reservoir conditions for UHS, focusing on both geochemical and geomechanical changes induced by hydrogen exposure. Static reactivity tests were conducted on various limestone samples at a constant pressure of 500 psi, exposed to different temperature conditions (25°C and 50°C) and brine over 30 days. Both dry and saturated states were tested to simulate diverse reservoir conditions. Parameters such as porosity, permeability, and Uniaxial Compressive Strength (UCS) were measured before and after exposure. Results showed that porosity remained stable across all conditions, suggesting hydrogen exposure does not significantly alter pore structure. However, permeability exhibited mixed responses, with increases observed in two out of three limestone types, indicating hydrogen exposure could enhance fluid flow in certain carbonate rocks. All samples exposed to elevated temperatures and saturation conditions demonstrated a reduction in UCS, indicating a weakening of mechanical integrity, which could impact structural stability and safety of UHS operations. The extent of weakening varied among limestone types, suggesting mineralogical composition plays a crucial role in rock response to hydrogen exposure. These findings provide critical insights into the geochemical and geomechanical behavior of carbonate rocks under hydrogen exposure. While UHS in carbonate reservoirs appears feasible, the significant reduction in UCS highlights potential risks to mechanical stability. Understanding these changes is essential for assessing the feasibility and safety of UHS projects in carbonate reservoirs. Future research should focus on long-term exposure tests and the development of mitigation strategies to address the mechanical weakening of reservoir rocks.
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Li, F. "Diagenetic Evolution of Bioclastic Limestone Reservoirs and its Effect on Reservoir Properties." In 83rd EAGE Annual Conference & Exhibition. European Association of Geoscientists & Engineers, 2022. http://dx.doi.org/10.3997/2214-4609.202210668.
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Bandy Jr., William F. "Reservoir Characterization of the Trenton Limestone, Illinois Basin." In 2022 Eastern Section AAPG Meeting: Energy for All. Tulsa, OK, USA: American Association of Petroleum Geologists, 2022. http://dx.doi.org/10.1306/11371bandy2022.
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Ali, Mehar, Chaudhary M. Saqib, Syed M. Iftikhar Rizvi, Nasir Hamim, Ahsan Javed, and Syed M. Usman Shah. "The Characterization of Geological Flow Units in Carbonate Reservoirs - Integration of Core, Log & Production Logging Data." In PAPG/SPE Pakistan Section Annual Technical Symposium and Exhibition. SPE, 2023. http://dx.doi.org/10.2118/217362-ms.
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Abstract Geological flow units based on reservoir rock typing can be used to characterize geological facies based on their dynamic behavior. A procedure for identifying and characterizing geological flow units helps resolve some of the key challenges faced in exploration and production of carbonate reservoirs. The current work focuses on the rock typing/flow units classification for reservoir characterization in a carbonate gas reservoir. The Sui Main Limestone (SML) Eocene reservoir, located in the southwestern part of the Middle Indus Basin in Baluchistan Province was selected, and the study carried out using core, wireline logs of 30+ wells and production logging data. The reservoir was previously categorized based on the geological information into four layers. An integrated workflow was used for characterization of Geological Flow Units based on all available information. The Sui Main Limestone (SML) reservoir was divided into three flow units/rock types, depending on the well log patterns, core data, Porosity–Water saturation relationships, flow zone indicators (FZIs), and the Porosity–Permeability relationships. Production logging data was used to validate flow unit classification. The field is a gas bearing reservoir composed of medium hard to hard limestone characterized by high porosity but poor/low permeability. The matrix permeabilities and porosity range from 0.01–40 mD and 0–35 percent respectively. Three rock types and groups have been identified in the SML formation; the first group represents the poor reservoir quality (GFU-1) Highly cemented limestone, the second group reflects the moderate reservoir quality (GFU-2) Moderately cemented limestone, and the third group represents the very good reservoir quality (GFU-3) poorly cemented limestone. Production logging data was used to validate flow unit classification. Pressure Transient Analysis (PTA) indicated that only partial penetration occurred, and therefore only a portion of the perforated area was contributing to production. Specifically, the majority of inflow zones identified in the production logging data corresponded to GFU-3 flow units. As expected, the other two flow units only provide a small increase in production. This further validated the partial penetration model determined from PTA. Geological flow units/rock types in these thick carbonate reservoirs and can be helpful in selecting optimum perforation intervals rather than perforating the whole thickness. This innovative method can save significant CAPEX without compromising the production.
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Gomes, Jorge, Jane Mason, and Graham Edmonstone. "Value of DTS in Multi-Stacked Reservoirs to Better Understand Injectivity and Water Flood Effectiveness – A Field Example from the UAE." In SPE Annual Technical Conference and Exhibition. SPE, 2021. http://dx.doi.org/10.2118/206103-ms.
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This paper highlights the application of downhole fiber optic (FO) distributed temperature sensing (DTS) measurements for well and reservoir management applications: 1) Wellbore water injectivity profiling. 2) Mapping of injection water movement in an underlying reservoir. The U.A.E. field in question is an elongated anticline containing several stacked carbonate oil bearing reservoirs (Figure 1). Reservoir A, where two DTS monitored, peripheral horizontal water injectors (Y-1 and Y-2) were drilled, is less developed and tighter than the immediately underlying, more prolific Reservoir B with 40 years of oil production and water injection history. Reservoirs A and B are of Lower Cretaceous age, limestone fabrics made up of several 4th order cycles, subdivided by several thin intra dense, 2-5 ft thick stylolitic intervals within the reservoir zones. Between Reservoir A and Reservoir B there is a dense limestone interval (30-50 ft), referred as dense layer in the Figure 1 well sections.
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Yan, Jun, Mingyue Cui, Anle He, Ning Qi, Weixiang Cui, and Xiaohong Wen. "Study on Boundary of Control Models and Mechanisms of Acid Rock Reaction in Carbonate Reservoirs with Different Dolomite Mass Fraction." In International Petroleum Technology Conference. IPTC, 2021. http://dx.doi.org/10.2523/iptc-21315-ms.
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Abstract The understanding of acid rock reaction kinetics is the basis for the proposal of carbonate rock acidizing and acid fracturing. So far, the study of acid rock reaction kinetics in carbonate reservoirs is mostly focused on limestone reservoirs. The difference in acid rock reaction characteristics between limestone and dolomite reservoirs is obvious. In order to clarify the boundaries of control models and mechanisms of acid rock reaction in dolomite reservoirs, to guide the optimization of acidizing and acid fracturing proposal for carbonate reservoirs with different dolomite contents. The experimental study of acid rock reaction kinetics was completed with carbonate cores with different dolomite mass fraction, and the difference of acid corrosion mechanism between limestone and dolomite was analyzed by scanning electron microscope. The dolomite acid rock reaction kinetics equation under the control of different factors was established, and it was clarified that the temperature 90°C and the rotation speed 500r/min are the boundary of the surface reaction and mass transfer control mode. The study found that under the same experimental conditions, the acid rock reaction rate of dolomite is much lower than that of limestone; as the dolomite mass fraction increases, the acid rock reaction rate decreases rapidly, when the dolomite content exceeds 75%, the reaction rate of acid rock is reduced to the lowest and tends to be stable. Limestone is dominated by surface dissolution, with good dissolution effect, fast dissolution rate; dolomite is dominated by point dissolution, with holes on the surface, poor dissolution effect and low dissolution rate. Compared with limestone, the particle size of dolomite crystal is much larger, and the specific surface area is small, which is also the reaction rate of acid rock in dolomite is slower than limestone, this is also a main reason why the reaction rate of dolomite acid rocks is slower than that of limestone. So the acidizing or acid fracturing methodology of the dolomite reservoir is different from that of the limestone reservoir. The acid rock reaction rate and hydrochloric acid concentration should be appropriately increased within the allowable range to improve the uneven etching of the fracture wall, thereby increasing increase the conductivity of acid fracture.
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Verberne, B. A., A. J. van der Linden, K. El Azouzi, T. K. T. Wolterbeek, R. van Schalm, and A. Coorn. "Effects of Rapid Cooling and CO2 Depressurization on the Compressive Strength of Limestone." In 57th U.S. Rock Mechanics/Geomechanics Symposium. ARMA, 2023. http://dx.doi.org/10.56952/arma-2023-0609.
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ABSTRACT CO2-injection into depleted reservoirs can lead to rapid cooling and a CO2 phase change in the near-wellbore region, potentially affecting rock mechanical integrity. We report unconfined compressive strength (UCS) and thick-walled cylinder (TWC) collapse strength tests on dry and brine-saturated limestones subjected to cooling (ΔT) or CO2 depressurization (ΔP). Plug samples were prepared from Indiana limestone and a limestone from the Green River Formation, outcropping in Sanpete Valley, Utah, USA. The ΔT-treatment consisted of a thermal shock from 60°C to −78°C, while the ΔP-treatment consisted of three cycles of rapid depressurization from ∼9 MPa CO2 pressure to atmosphere. The ΔP-treatment was performed at room temperature and at 60°C. The results show that dry samples are generally stronger than their brine-saturated counterparts, while effects from ΔT- or ΔP-treatment on rock strength or stiffness are indiscernible. Based on our findings on the Indiana and Green River Formation limestones, we suggest that CO2-injection-induced cooling or depressurization in limestone reservoirs can lead to strengthening of desiccated regions with negligible negative impact on rock mechanical integrity. INTRODUCTION Carbon capture and storage (CCS) is a key strategy on the way to a net-zero CO2-emissions industry, including in carbonate reservoirs, which constitute vast potential storage volumes (e.g., Bonto et al., 2021). However, large-scale implementation of CCS will only be viable if operational risks are understood and mitigated. One of the important geomechanical concerns for geological CO2 sequestration are thermal stress effects due to injection of relatively cold CO2 (Rutqvist, 2012; Roy et al., 2018). Especially in cases where the reservoir (residual) pore pressure is substantially lower than the intended CO2 supply pressure (typically >7 MPa), adiabatic, isenthalpic expansion of CO2 in the near-wellbore region can lead to sharp temperature drops, possibly even reaching below freezing conditions (Oldenburg, 2007; Mathias et al., 2010). Rapid temperature changes can result in thermal strains, fracturing, and, potentially, loss of containment (Pašić et al., 2007; Wang et al., 2022).
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Shchipanov, A. A., A. S. Nekrasov, O. Fonta, and D. V. Potekhin. "Modeling of Fracturing of Limestone Petroleum Reservoir Using Fraca Technology." In 2nd EAGE St Petersburg International Conference and Exhibition on Geosciences. European Association of Geoscientists & Engineers, 2006. http://dx.doi.org/10.3997/2214-4609-pdb.20.p202.
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Yokoyama, Y., and E. Arima. "Pilot Development of Tight Limestone Reservoir in the Khafji Field." In SPE Asia-Pacific Conference. Society of Petroleum Engineers, 1989. http://dx.doi.org/10.2118/19488-ms.
Full textReports on the topic "Limestone reservoir"
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Hammouti, A., S. Larmagnat, C. Rivard, and D. Pham Van Bang. Use of CT-scan images to build geomaterial 3D pore network representation in preparation for numerical simulations of fluid flow and heat transfer, Quebec. Natural Resources Canada/CMSS/Information Management, 2023. http://dx.doi.org/10.4095/331502.
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Non-intrusive techniques such as medical CT-Scan or micro-CT allow the definition of 3D connected pore networks in porous materials, such as sedimentary rocks or concrete. The definition of these networks is a key step towards the evaluation of fluid flow and heat transfer in energy resource (e.g., hydrocarbon and geothermal reservoirs) and CO2 sequestration research projects. As material heterogeneities play a role at all scales (from micro- to project-scale), numerical models represent a powerful tool for bridging the gap between small-scale measurements provided by X-ray imaging techniques and larger-scale transport properties. This study uses pre-existing medical CT-scan datasets of reference material, namely glass beads and conventional reservoir rocks (Berea sandstone, Boise sandstone, Indiana limestone) to extract the 3D geometry of connected pores using an open-source software (Spam). Pore networks from rock samples were generated from dry and then saturated samples. Binarized datasets were produced for these materials (generated by a thresholding technique) to obtain pore size distribution and tortuosity, as well as preferential paths for fluid flow. Average porosities were also calculated for comparison with those obtained by conventional commercial laboratory techniques. The results obtained show that this approach works well for medium and coarse-grained materials that do not contain a large percentage of fine particles. However, this approach does not allow representative networks to be obtained for fine-grained rocks, due to the fact that small pores (or pore throats) cannot be taken into account in the datasets obtained from the medical CT-Scan. A next step, using datasets produced from a micro- CT scan, is planned in order to be able to generate representative networks in this type of material as well.
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Carter, T. R., C E Logan, and H. A. J. Russell. Three-dimensional model of dolomitization patterns in the Salina Group A-1 Carbonate and A-2 Carbonate units, Sombra Township, Lambton County, southern Ontario. Natural Resources Canada/CMSS/Information Management, 2024. http://dx.doi.org/10.4095/332363.
Full textAbstract:
Dolomitization of carbonate rocks is a subject of considerable interest due to association with oil and gas reservoirs and Mississippi Valley Type ore deposits. Conceptual two-dimensional models of dolomitization are common in the literature, however numeric models supported by high quality data are rare to nonexistent. This paper presents three-dimensional (3-D) dolomitization patterns in the Salina Group A-1 Carbonate Unit and A-2 Carbonate Unit located in Sombra Township, Lambton County. The source data consists of percent dolomite measurements collected from 9727 drill cutting samples, stained with alizarin red, from 409 petroleum wells. Numerical interpolants of the percentage of dolomite versus limestone in the two formations are developed within the boundaries of lithostratigraphic formation layers derived from a 3-D geologic model of southern Ontario, published as GSC Open File 8795 (Carter et al. 2021b). The model was developed using Leapfrog© Works software with a 400 m grid resolution. Results show that increased proportions of dolomite vs limestone in both formations are spatially associated with the flanks and crests of pinnacles in the underlying Lockport Group carbonates, over which the B Salt has been dissolved, and the downthrown side of the Dawn Fault and Becher faults. In the A-1 Carbonate there is an increase in dolomite content over a minority of incipient reefs in the Lockport, and in the A-2 Carbonate Unit there is a gradational increase in dolomite content upwards from a basal limestone to 100% dolomite. The cross-cutting relationships of dolomite occurrence in the A-1 Carbonate on the flanks and crests of some pinnacles support a post-depositional burial diagenesis mechanism, consistent with previous interpretations. The pathway for the dolomitizing fluid was laterally through porous and permeable regional paleokarst in the underlying Lockport Group, uppermost Goat Island and Guelph formations, and upwards through the porous reefal carbonates of the pinnacles. Association of dolomitization haloes with dissolution features in halite of the overlying B Salt Unit further suggest that the dolomitizing fluids were also responsible for salt dissolution. The preferential association of dolomite with the Dawn and Becher faults suggest that movement of the dolomitizing fluid was also fault controlled. This project demonstrates the feasibility and merit of assignment and interpolation of attribute values constrained by lithostratigraphic layers in the regional 3-D geologic model of southern Ontario. Spatial associations of dolomite with other geological features are more clearly resolved than in a 2-D study.
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Sun, S., F. R. Brunton, T. R. Carter, J. R. Clarke, H. A J Russell, K. Yeung, A. Cachunjua, and J. Jin. Porosity and permeability variations in the Silurian Lockport Group and A-1 carbonate unit, southwestern Ontario. Natural Resources Canada/CMSS/Information Management, 2023. http://dx.doi.org/10.4095/331902.
Full textAbstract:
This is the first regional porosity/permeability study to incorporate petroleum industry laboratory core analyses submitted to the Ontario government and managed by Ontario's Oil Gas and Salt Resources Library. This study comprises 11,759 analyses for the Early Silurian Lockport Group of southwestern Ontario from 150 drill cores. The Lockport Group consists of a cyclic succession of dolostones and minor limestones comprising, in ascending order: Gasport, Goat Island, Eramosa, and Guelph formations. This stacked carbonate succession was deposited on an eastward-deepening carbonate ramp, extending from Michigan, through southwestern Ontario, to Ohio, Pennsylvania and New York. It is overlain disconformably by restricted marine carbonates, evaporites and mixed shales of the Salina Group, whereas unconformably underlain by one of four formations that include, the Lions Head (a stratigraphic equivalent of part of the Rochester), DeCew, Rochester and Irondequoit. To ensure appropriate stratigraphic assignment of the laboratory test intervals, a quality assurance/quality control review on formational tops was carried out on the 150 cores that were tested. This regional subsurface work resulted in the reassignment of 846 formation tops that were verified by examination of drill core, drill cuttings, and geophysical well data including gamma-ray, neutron and density logs. Core analysis datasets have been validated by summarizing laboratory protocols and standards and reconciling data fields in the core analysis database with auxiliary data, including geophysical logs, thin sections, and core examinaion. This auxiliary data was then used to identify data outliers to update the core analysis database. The measurements of porosity and permeability were then assigned a formation rank plotted on a subregional scale. Average porosity and permeability values have been divided into statistical populations for each formation assigned by three depositional realms. The southwestern Ontario study area has been divided into three paleogeographic settings, based on distinctive lithofacies that correspond to different carbonate depositional regimes and regions of paleokarstification. From northwest to southeast, the lithofacies reflect an inner to outer carbonate ramp setting designated as area 1-3 from northwest to southeast. Area 1 is the inter-pinnacle karst region and includes some of thepinnacle structures within the Lockport Group. This region has the most significant paleokarstification of the upper Lockport Group (Guelph and Goat Island formations) and overlying Salina Group A-unit. Area 2 has rare pinnacle structures, where no porosity/permeability core analyses data are available. Area 3 is the middle to outer portion of the Lockport carbonate ramp, with local development of reef mound phases in the lower Goat Island and Gasport formations. The porosity and permeability variability corresponds with areal distribution of paleokarstification and resulting diagenetic phases in Area 1, and lithofacies variations and temporal/spatial history of karstification in Area 3. Higher porosity and permeability generally coincide with greater thicknesses of the oil and gas reservoir within pinnacles in Area 1 and reef mound phases of Lockport Group and lower Salina Group A-1 Carbonate in Area 3. Within inter-pinnacle karst regions in Area 1, average porosity for each formation is consistently high with little variations. In Area 3, a general increase of porosity and permeability towards the southeast corresponds with lithofacies ranging from restricted lagoonal/platform interior deposits to carbonate bank deposits with local development of reef mound phases in the Gasport and Goat Island formations. There has been significant erosion and karstification within and at the tops of these pinnacles, resulting in higher porosity and permeability of the Guelph and upper Goat Island formations, and the overlying Salina Group A-1 unit. Paleokarstic events have enhanced various porosity types, including intercrystalline, moldic, irregular and fenestral vugs, and cavities.