Fluid Histories of Middle Ordovician fault–fracture hydrothermal dolomite oil fields in the southern Michigan Basin, U.S.A.

2021 ◽  
Vol 91 (10) ◽  
pp. 1067-1092
Author(s):  
Regina F. Dunseith ◽  
Jay M. Gregg ◽  
G. Michael Grammer
Keyword(s):  
Oil Field ◽  
Oil Fields ◽  
Michigan Basin ◽  
Middle Ordovician ◽  
Carbonate Cements ◽  
Saddle Dolomite ◽  
Homogenization Temperatures ◽  
Calcite Cement ◽  
Proterozoic Basement ◽  
Two Fluid

ABSTRACT Dolomitized fault–fracture structures in the Trenton and Black River formations (TBR) are the type example for “hydrothermal” petroleum reservoirs world-wide. However, fluid histories of these structures are only partially understood. Trenton and Black River reservoirs in the southern Michigan Basin are composed of fault-associated, vertical dolomite bodies that are highly fractured and brecciated. Open spaces are partially to completely filled by saddle dolomite and less frequently by calcite cement. Cathodoluminescence microstratigraphies of void-filling carbonate cements are not correlatable between oil fields. Fluid inclusion homogenization temperatures (Th) measured in carbonate cements indicate two fluid endmembers: a warm fluid (∼ 80° to 180° C) and a hot fluid (180° to ∼ 260° C). Increasing Th proximal to the underlying Proterozoic Mid-Michigan Rift (MMR) suggest that the hot fluids emanated from the rift area. Included fluids are saline (16.1–49.4 wt. % NaCl equivalent), and salinity likely is sourced from overlying Silurian Salina Group evaporites. First melting temperatures (Tfm), interpreted as eutectic temperatures (Te), of fluids range from –112° C to –50° C, indicating a complex Na–Ca–KCl brine; the expected composition of dissolved Salina salts. Lower Te proximal to the MMR suggest the rift as a source of additional complexing ions. C and O isotope values for carbonate cements are depleted with respect to δ18O (–6.59 to –12.46‰ VPDB) relative to Ordovician seawaters, and somewhat depleted with respect to δ13C (–1.22 to +1.18‰ VPDB). Equilibrium calculations from δ18O and Th values indicate that cement precipitating waters were highly evolved (+1.3 to +14.4‰ δ18O‰ VSMOW) compared to Ordovician and Silurian seawaters (–5.5‰ δ18O‰ VSMOW). Strontium isotope values indicate two fluid sources: Proterozoic basement and Late Silurian evaporites. Values of 87Sr/86Sr for cements in the Freedom, Napoleon, Reading, and Scipio fields (0.7086–0.7088) are influenced by warm water sourced from Silurian strata, and values for cements in the Albion, Branch County, and Northville fields (0.7091–0.7110) record continental basement signatures. Cement precipitating fluids in TBR oil fields likely have similar sources and timing. However, water–rock interactions along fault pathways modified source waters, giving each oil field a unique petrographic and geochemical signature. Fluid movement in TBR oil fields likely were initiated by reactivation of basement faulting during Silurian–Devonian tectonism.

MIDDLE ORDOVICIAN HYDROTHERMAL DOLOMITE OIL FIELDS OF THE SOUTHERN MICHIGAN BASIN

2019 ◽  
Author(s):  
Jay M. Gregg ◽  
◽  
Regina F. Dunseith ◽  
G. Michael Grammer
Keyword(s):  
Oil Fields ◽  
Michigan Basin ◽  
Middle Ordovician ◽  
Hydrothermal Dolomite

scholarly journals Fluid compartmentalization of Devonian and Mississippian dolostones, Western Canada Sedimentary Basin: petrologic and geochemical evidence from fracture mineralization

2019 ◽  
Vol 56 (3) ◽  
pp. 265-305 ◽  
Author(s):  
Ihsan S. Al-Aasm ◽  
Carole Mrad ◽  
Jeffery Packard
Keyword(s):  
Sedimentary Basin ◽  
Hydrothermal Systems ◽  
Fluid Inclusion Study ◽  
Isotopic Ratios ◽  
Western Canada ◽  
Western Canada Sedimentary Basin ◽  
Saddle Dolomite ◽  
Homogenization Temperatures ◽  
Calcite Cement ◽  
Canada Sedimentary Basin

Integrated petrographic, geochemical, and fluid inclusion study of fracture mineralization and associated host rock in selected Mississippian and Devonian carbonates extending from southeastern Alberta to northwestern British Columbia, Canada, aims to quantify the type and nature of fluid precipitated saddle dolomite and late calcite cement and their origin. Petrographic and isotopic evidence from both the Devonian and Mississippian fracture-filling carbonates indicate the presence of a hydrothermal fluid source. The δ18O isotopic values for the Devonian saddle dolomite (−14.62‰ to −3.75‰ VPDB, average −11.12‰) combined with enriched 87Sr/86Sr isotopic ratios (0.70827–0.71599, average 0.71006) and higher homogenization temperatures (Th = 74–194.6 °C, average 126.8 °C) and salinity values (7.7–26.6 wt.% NaCl, average 16.2 wt.% NaCl) show significant differences from the Mississippian saddle dolomite, which is characterized by less negative δ18O isotopic values (−12.53‰ to −7.82‰ VPDB, average −9.14‰), less radiogenic 87Sr/86Sr isotopic ratios (0.70859–0.70943, average 0.70887), and lower homogenization temperatures (Th) and salinity values of fluid inclusions (87.6–214.2 °C, average 136.3 °C; 2.0–13.2 wt.% NaCl, average 9.6 wt.% NaCl). Later fracture- and vug-rimming blocky calcite cement records comparable or slightly lower values of δ18O (−16.31‰ to −4.08‰ VPDB, average −9.76‰) and 87Sr/86Sr (0.70784–0.709743, average 0.70868) and much lower salinity values (0–22.5 wt.% NaCl, average 2.86 wt.% NaCl) for samples mostly from the Mississippian age group. These results possibly suggest two different hydrothermal episodes related to early (Antler) and late (Laramide) tectonic events that affected the Western Canada Sedimentary Basin with possible compartmentalization of hydrothermal systems and their associated brines in the basin.

Flow Assurance in Buzios Field: Key Challenges and Implemented Solutions

2021 ◽  
Author(s):  
Ivan Noville ◽  
Milena da Silva Maciel ◽  
Anna Luiza de Moraes y blanco de Mattos ◽  
João Gabriel Carvalho de Siqueira
Keyword(s):  
Liquid Flow Rate ◽  
Hydrate Formation ◽  
Oil Field ◽  
Oil Fields ◽  
Injection System ◽  
Flow Assurance ◽  
Water Alternating Gas ◽  
Early Design Stages ◽  
Scale Deposition ◽  
Full Operation

Abstract This article's goal is to present some of the main flow assurance challenges faced by PETROBRAS in the Buzios oil field, from its early design stages to full operation, up to this day. These challenges include: hydrate formation in WAG (Water Alternating Gas) operations; reliability of the chemical injection system to prevent scale deposition; increasing GLR (Gas Liquid Ratio) management and operations with extremely high flowrates. Flow assurance experience amassed in Buzios and in other pre-salt oil fields, regarding all these presented issues, is particularly relevant for the development of future projects with similar characteristics, such as high liquid flow rate, high CO2 content and high scaling potential.

Numerical Simulation of Gas Lift Optimization Using Artificial Intelligence for a Middle Eastern Oil Field

2021 ◽  
Author(s):  
Mohammed Ahmed Al-Janabi ◽  
Omar F. Al-Fatlawi ◽  
Dhifaf J. Sadiq ◽  
Haider Abdulmuhsin Mahmood ◽  
Mustafa Alaulddin Al-Juboori
Keyword(s):  
Genetic Algorithm ◽  
Sensitivity Analysis ◽  
Middle Eastern ◽  
Optimization Technique ◽  
Injection Rate ◽  
Oil Field ◽  
Oil Fields ◽  
Reservoir Pressure ◽  
Artificial Lift ◽  
Gas Lift

Abstract Artificial lift techniques are a highly effective solution to aid the deterioration of the production especially for mature oil fields, gas lift is one of the oldest and most applied artificial lift methods especially for large oil fields, the gas that is required for injection is quite scarce and expensive resource, optimally allocating the injection rate in each well is a high importance task and not easily applicable. Conventional methods faced some major problems in solving this problem in a network with large number of wells, multi-constrains, multi-objectives, and limited amount of gas. This paper focuses on utilizing the Genetic Algorithm (GA) as a gas lift optimization algorithm to tackle the challenging task of optimally allocating the gas lift injection rate through numerical modeling and simulation studies to maximize the oil production of a Middle Eastern oil field with 20 production wells with limited amount of gas to be injected. The key objective of this study is to assess the performance of the wells of the field after applying gas lift as an artificial lift method and applying the genetic algorithm as an optimization algorithm while comparing the results of the network to the case of artificially lifted wells by utilizing ESP pumps to the network and to have a more accurate view on the practicability of applying the gas lift optimization technique. The comparison is based on different measures and sensitivity studies, reservoir pressure, and water cut sensitivity analysis are applied to allow the assessment of the performance of the wells in the network throughout the life of the field. To have a full and insight view an economic study and comparison was applied in this study to estimate the benefits of applying the gas lift method and the GA optimization technique while comparing the results to the case of the ESP pumps and the case of naturally flowing wells. The gas lift technique proved to have the ability to enhance the production of the oil field and the optimization process showed quite an enhancement in the task of maximizing the oil production rate while using the same amount of gas to be injected in the each well, the sensitivity analysis showed that the gas lift method is comparable to the other artificial lift method and it have an upper hand in handling the reservoir pressure reduction, and economically CAPEX of the gas lift were calculated to be able to assess the time to reach a profitable income by comparing the results of OPEX of gas lift the technique showed a profitable income higher than the cases of naturally flowing wells and the ESP pumps lifted wells. Additionally, the paper illustrated the genetic algorithm (GA) optimization model in a way that allowed it to be followed as a guide for the task of optimizing the gas injection rate for a network with a large number of wells and limited amount of gas to be injected.

scholarly journals The use of the method of controlling the electrochemical parameters of aqueous solutions to combat complications in the operation of oil field pipelines

2021 ◽  
Vol 225 ◽  
pp. 01008
Author(s):  
Oleg Latypov ◽  
Sergey Cherepashkin ◽  
Dina Latypova
Keyword(s):  
Aqueous Solutions ◽  
Oil And Gas ◽  
High Efficiency ◽  
Oil Field ◽  
Oil Fields ◽  
Control Methods ◽  
Test Results ◽  
Chemical Reagents ◽  
Electrochemical Parameters ◽  
Very High

Corrosion of equipment in the oil and gas complex is a global problem, as it contributes to huge material costs and global disasters that violate the environment. Corrosion control methods used to protect equipment do not always ensure the absolute safety of the operation of oil and gas facilities. Moreover, they are quite expensive. The developed method for controlling the electrochemical parameters of aqueous solutions to combat complications during the operation of oil-field pipelines provides the necessary protection against corrosion. The method is economical and environmentally friendly, since it does not require the use of chemical reagents. The test results have shown a very high efficiency in dealing with complications in oil fields.

scholarly journals Metallic Composition Analysis of Crude Petroleum from Some Oil Fields in Ghana

2021 ◽  
pp. 19-29
Author(s):  
Robert Wilson ◽  
Calvin Kwesi Gafrey ◽  
George Amoako ◽  
Benjamin Anderson
Keyword(s):  
Chemical Elements ◽  
Earth Metal ◽  
Oil Field ◽  
Oil Fields ◽  
Composition Analysis ◽  
Crude Petroleum ◽  
Reservoir Properties ◽  
Exciting Field ◽  
Nuclear Research Institute ◽  
X Ray

Qualitative and quantitative analyses of chemical elements in crude petroleum using energy-dispersive X-ray fluorescence spectroscopic technique has attracted the attention of scientific world because it is fast, cheap, non-destructive and assurance in quality compared to other methods. Metallic element characterisation of crude petroleum is important in the petrochemical industry because it determines rock reservoir properties, the technology needed for extraction and refinery process, hence an exciting field that calls for research. X-ray fluorescence method was used for metallic composition analysis of four rundown crude petroleum samples (SB-2, SB-4, TB-2 and TB-1) from three oil fields (Saltpond, TEN and Jubilee). It was conducted at the National Nuclear Research Institute of Ghana. Analysis of the four samples concluded that oil field maturity decreases orderly from Saltpond, Jubilee and TEN. Vanadium-nickel ratios for each crude petroleum sample was less than 0.5, indicating that both Saltpond and Tano sedimentary rocks are of marine organic origin. Higher concentration levels of rare earth metal elements (scandium and yttrium) in the Saltpond sedimentary basin compared to Tano sedimentary rock suggest seismic effect of McCarthy Hills on Saltpond Basin. The strong negative correlation between the vanadium-nickel ratio (predictor) and scandium concentration (dependent) among the three oil fields implies that scandium concentration can equally be used to characterise the oil fields just as the vanadium-nickel ratios.

scholarly journals Naturally occurring radioactive materials and related hazard indices in Ahdeb oil field

2019 ◽  
Vol 13 (27) ◽  
pp. 164-173
Author(s):  
Zainab Mohammed Hassan
Keyword(s):  
Crude Oil ◽  
Activity Concentration ◽  
International Comparisons ◽  
Oil Field ◽  
Oil Fields ◽  
Hazard Indices ◽  
Radioactive Materials ◽  
Naturally Occurring ◽  
Naturally Occurring Radioactive Materials ◽  
Crude Oil Sludge

In this work, measurements of activity concentration of naturally occurring radioactive materials (NORM) isotopes and their related hazard indices for several materials such as crude oil, sludge and water in Ahdeb oil fields in Waste governorate using high pure germanium coaxial detection technique. The average values for crude oil samples were174.72Bq/l, 43.46Bq/l, 355.07Bq/l, 264.21Bq/l, 122.52nGy/h, 0.7138, 1.1861, 0.601 mSv/y, 0.1503mSv/y and 1.8361 for Ra-226, Ac-228, K-40, Ra eq, D, H-external and H-internal respectively. According to the results; the ratio between 238U to 232Th was 4, which represents the natural ratio in the crust earth; therefore, one can be strongly suggested that the geo-stricture of the Ahdeb oil fields dose not contents any kind of rocks. Although the results indicate the rising in the activity concentration of NORM isotopes, the national and international comparisons proved that it is still in the world range limits.

Thermal and hydrocarbon-charge history and the relationship between diagenesis and reservoir connectivity: Venture field, offshore Nova Scotia, eastern Canada1Geological Survey of Canada Contribution 20100418.

2011 ◽  
Vol 48 (9) ◽  
pp. 1293-1306 ◽  
Author(s):  
Atika Karim ◽  
Georgia Pe-Piper ◽  
David J.W. Piper ◽  
Jacob J. Hanley
Keyword(s):  
Nova Scotia ◽  
Fluid Inclusions ◽  
Upper Jurassic ◽  
Gas Reservoirs ◽  
Carbonate Cements ◽  
Migration History ◽  
Carbonate Cementation ◽  
Homogenization Temperatures ◽  
Hydrocarbon Charge ◽  
Reservoir Connectivity

Fluid inclusions in diagenetic cements in Upper Jurassic – Lower Cretaceous sandstones offshore Nova Scotia provide constraints on the fluid migration history in gas reservoirs of the Scotian basin. Diagenetic minerals from six wells in the Venture field were analysed by optical petrography, scanning electron microscopy (SEM), and electron microprobe. A total of 122 primary and secondary fluid inclusions were analysed from different cements. Primary aqueous inclusions in quartz overgrowths have homogenization temperatures (Th) of 111.8 ± 7.1 °C (1σ) and in later carbonate cements 126.5 ± 2.1 °C; inclusions in both cements are highly saline (16–26.1 wt.% NaCl equivalent). Secondary aqueous and hydrocarbon-bearing inclusion trails crosscutting silica cement and detrital quartz have Th of 121.6 ± 13.6 °C and low salinities (8.7 ± 6.0 wt.%). Secondary carbonic inclusions have CO2 melting temperatures (–56.6 ± 0.1 °C) and Th (–9.3 ± 0.8 °C) indicating a high-density carbonic phase. Late carbonate cements in the same sandstone units vary in chemical composition in different wells, and connected reservoirs show similar late carbonate assemblages, suggesting that the late carbonate cementation may be partly controlled by the reservoir fill and spill sequence. Silica and late carbonate cementation involved highly saline fluid flow, likely at about ∼135 Ma. Hydrocarbon migration postdated silica cementation and was associated with secondary fracturing, suggesting that it corresponded to the onset of overpressure.

Hydrothermal dolomitization in the Lower Silurian Sayabec Formation in northern Gaspé – Matapédia (Québec): constraint on timing of porosity and regional significance for hydrocarbon reservoirs

2004 ◽  
Vol 52 (3) ◽  
pp. 256-269 ◽  
Author(s):  
Denis Lavoie ◽  
Claude Morin
Keyword(s):  
High Temperature ◽  
Stable Isotope ◽  
Isotope Ratios ◽  
Stable Isotope Ratios ◽  
Lower Silurian ◽  
The Matrix ◽  
Saddle Dolomite ◽  
Northern Edge ◽  
Calcite Cement ◽  
Hydrocarbon Charge

Abstract The study of dolostone of the Lower Silurian Sayabec Formation of the Lac Matapédia syncline, at the western end of the Gaspé Peninsula, sheds new light on porosity development and reservoir potential of the area. The dolomitized section is close to the Shickshock Sud Fault that cuts the southern limb of the syncline. The dolostone occurs either as a highly brecciated unit or as stratiform replacement of peritidal carbonates at the base of the formation. Residual bitumen is seen in the breccia as well as filling of small secondary vugs and fractures within the stratiform dolostone. The dolostone consists predominantly of replacive matrix dolomite; petrography and oxygen and carbon stable isotope ratios (δ18OVPDB = −6.3 to −7.8‰ and δ13CVPDB = 1.2 to 3.3‰) of the matrix dolomite indicate early burial formation with later recrystallization in the presence of high temperature fluids. Saddle dolomite is found as a pore-filling cement in secondary dissolution pores and fractures. Oxygen stable isotope ratios of the saddle dolomite cement (δ18OVPDB = −14.5 and −15.3‰) indicate precipitation at high temperature. Dull luminescent burial calcite cement follows saddle dolomite. Later dissolution is locally apparent in carbonates as scalloped surfaces covered by finely laminated, bright-very dull luminescent calcites. Petrography and stable isotope ratios of the calcite (δ18OVPDB = −10.1 and −11.2‰ and δ13CVPDB = −2.3 and −6.9‰) suggest precipitation from meteoric waters. Meteoric dissolution and luminescent-zoned calcite cements are related to a Pridolian sea level lowstand. This event provides a first age constraint on the timing of the hydrothermal dolomitization and hydrocarbon charge of the Sayabec Formation along the northern edge of the Gaspé Belt. The Shickshock Sud Fault channelled the hydrothermal fluids, which dolomitized the Sayabec Formation shortly after initial burial. A recent regional seismic program showed compressive structures (duplexes, backthrust, triangle zone) in the Sayabec Formation inferred to have occurred in latest Silurian–Early Devonian that generated structural traps superimposed on the stratigraphic (shaly facies) and diagenetic (tight non-dolomitized limestone) seals. Seismic anomalies (“flat spots”) in the Lower Silurian section in eastern Quebec suggest the presence of hydrocarbon-filled reservoirs.

Laboratory studies of oil-washing characteristics of surfactants in the pore space of reservoir rocks

2021 ◽  
pp. 86-98
Author(s):  
V. Yu. Ogoreltsev ◽  
S. A. Leontiev ◽  
A. S. Drozdov
Keyword(s):  
Oil Recovery ◽  
Pore Space ◽  
Oil Field ◽  
Oil Fields ◽  
Molecular Surface ◽  
Laboratory Studies ◽  
Reservoir Rocks ◽  
Technological Efficiency ◽  
Chemical Eor ◽  
Physical And Chemical

When developing hard-to-recover reserves of oil fields, methods of enhanced oil recovery, used from chemical ones, are massively used. To establish the actual oil-washing characteristics of surfactant grades accepted for testing in the pore space of oil-containing reservoir rocks, a set of laboratory studies was carried out, including the study of molecular-surface properties upon contact of oil from the BS10 formation of the West Surgutskoye field and model water types with the addition of surfactants of various concentrations, as well as filtration tests of surfactant technology compositions on core models of the VK1 reservoir of the Rogozhnikovskoye oil field. On the basis of the performed laboratory studies of rocks, it has been established that conducting pilot operations with the use of Neonol RHP-20 will lead to higher technological efficiency than from the currently used at the company's fields in the compositions of the technologies of physical and chemical EOR Neonol BS-1 and proposed for application of Neftenol VKS, Aldinol-50 and Betanol.

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