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Collaborating Authors
Technical Meeting / Petroleum Conference of The South Saskatchewan Section
Co-Current And Counter-Current Imbibition Analysis For Tight Fractured Carbonate Gas Reservoirs
Kantzas, A. (University of Calgary/Tomographic Imaging and Porous Media Laboratory) | Pow, M. (Husky Oil Operations) | Allsopp, K. (Tomographic Imaging and Porous Media Laboratory) | Marentette, D. (Tomographic Imaging and Porous Media Laboratory)
Abstract The problem of low productivity natural gas reservoirs that are positioned over active aquifers is addressed. The principles of co-current and counter-current imbibition as used in fractured oil reservoirs are adopted for application in natural gas formations. Experiments were performed on core samplesfrom Western Canada and on Berea sandstone. The tests involved both co-current and counter-current primary and spontaneous imbibition. The production of gas was measured through weight increases in the core samples. Long term effects of the imbibition process were also observed. Furthermore, visualization experiments using glass micromodels were performed. The results to date indicate that the imbibition process in natural gas reservoirs is also direction oriented. Large amounts ofothenvise producible gas will be trapped because of the elimination of accessible pathways from the fast advancing water. The potential of gas migration through these pathways is addressed. Moreover, the productivity increase of such wells is discussed. It is concluded that alternative methods for the recovery of these reservoirs must be sought. Introduction The topic of water imbibition in fractured reservoirs has been studied for over forty years. Aronofsky et. al. I used an exponential type of formula to correlate oil recovery data from fractured reservoirs. The equation used is as follows: Equation (1) (Available in full paper) In the figures of the Aronofsky et al. paper, one can see that the mean water rise as a function of time reaches a first plateau where the oil recovery slows down after an accelerated period. This is followed by a second stage of water saturation process to higher saturation values. This trend appears as though the imbibition process slows down before it starts up again. Gupta and Civan extended this work to include contact angle effects. Iffly et al. have performed a large number of laboratory tests on fluids and porous media taken from a field exploited by ELF to ascertain the waterflood efficiency in a fissured oil-field. Their results demonstrated the interactions between connate water, injected brine, oil and rock at any time during imbibition. They found that increasing carbonate content and organic matter in the sands decreases the recovery of oil. They further found that gravity was a very important factor in the onset of imbibition. They postulated that the recovery evolution with time is a function of too many parameters to be described by a simple law. Fissure size and initial saturation were not found to drastically affect oil recovery within the limits of their study. Hammon and Vidal studied the effects of the height and the boundary conditions of water-imbibing samples on oil recovery curves versus time. They found that conventional two-phase flow equations describe the relevant mechanisms. Also, the imbibition capillary pressure curves of small samples could be used confidently for scale-up. The fracture spacing and the geometry of the fissure network have a strong influence on the oil recovery rate. Ultimate oil recovery appears to be independent of the boundary conditions for water-wet rocks.
- North America > Canada (1.00)
- North America > United States > West Virginia (0.26)
- North America > United States > Pennsylvania (0.26)
- (2 more...)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Naturally-fractured reservoirs (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Carbonate reservoirs (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (0.90)
Introduction TransGas Limited (TGL) currently owns and operates 24 salt caverns for the storage of natural gas. These storage caverns were developed in an extensive salt bed running through the province of Saskatchewan called the Prairie Evaporite, see figure 1 in the appendix. TransGas was the owner, operator, and user of all our storage caverns until 1988. In 1988 TransGas was split from the provincial crown electric utility and became a separate crown corporation. The new company had two components, a local distribution company (LDC) and a transmission & storage company. Initially the only storage customers were the electric utility and the LDC. In 1990 TransGas started to market our storage services to other customers. This meant increased demand for our storage services. TGL usually produced gas during the winter season and injected gas in the summer months, (one injection/production cycle per year). With the market expansion more frequent cycling of gas in storage was anticipated. The expansion in market also meant maximizing the useable volume of the storage facilities. TransGas traditionally set the minimum cavern operating pressure of our storage caverns at the expected transmission pipeline pressure. The resultant minimum bottomhole pressures were 0.12 to 0.13 psi/ft of depth to the cavern roof. The minimum cavern pressure was rarely reached prior to 1990. The maximum bottomhole cavern pressure was based on the depth to the cavern roof, 0.70 psi/fool. We had experienced some problems with three of our Regina caverns. Roof falls and side wall falls had resulted in the derating of these caverns. We decided the time was right to closely examine the design pressure of our caverns. Specifically we wanted answers to the following questions:Was our minimum design pressure acceptable? Was our maximum design pressure acceptable. Could we lower our minimum design pressure? Could we raise our maximum design pressure? Could we increase the useable volume of our caverns by changing the operating pressures? What impact did cycling have on the caverns. To determine the answers to these questions TransGas hired two consultants to assist with modeling our caverns. The two consultants were Dr. Gabe Fernandez and Murray Forster. Dr Fernandez is a Geotechnical Consultant and professor at University of Illinois Murray Forster is a Geotechnical Consultant in Saskatchewan. Doug Ruse, a local consultant, also reviewed the results of theses studies. This report summarizes the fmdings of these studies. Prairie Evaporite Salt Bed Material Properties Salt is a unique material. Salt's material properties depend on how it is loaded. When salt is loaded at low levels it will creep and deform. This creep and deformation ability is what makes salt "self-healing". Potash mines in Saskatchewan have experienced failure at stress levels well below that indicated by lab analysis. Dr. Malcolm Reeves of the University of Saskatchewan published a paper on "Dynamic brittle-rupture stable creep criteria in evaporite mine design". In his paper Dr. Reeves discusses the effect of stress on strain rate.
- Geology > Geological Subdiscipline > Geomechanics (0.74)
- Geology > Rock Type > Sedimentary Rock > Evaporite (0.68)
Abstract The possibility of relaxing basic sediment and water (BS&W) limits in pipelines has been gaining the interest of some Canadian producers. Some of this interest was engendered by comparing pipeline regulations in Canada to those in the United States. Currently in Canada. crude oil to be pipelined must contain Less than 0.5% by volume of BS&W In the United States, however, BS&W Limits in crude oil vary with each pipeline company, usually from 0.5% to 3%. American companies were surveyed as to whether they experience any more pipelining or processing difficulties than do their Canadian counterparts. Canadian producers. pipeliners, and upgraders/refiners were surveyed about their separate targets for and concerns about water and solids in crude oil. In all. 55 representatives from 45 sites participated in the survey. This paper is a brief non-confidential excerpt from the contract report done for Husky Oil. Petro-Canada, Wascana Energy and Saskatchewan Research Council. BACKGROUND Crude oil must meet a number of specifications for pipeline transportation. Pipeline companies and refineries frequently set maximum limits on basic sediment and water (BS&W) and salt content. While maximum limits on solids and salt are necessary to prevent downstream problems for pipelines and refineries. stringent limits on water may not be so crucial. In Canada, crude oil to be transported must contain less than 0.5% by volume of water and solids. In the United Slates. BS&W limits in crude oil vary with each pipeline company. usually from 0.5% to 3%. The question of whether these American companies experience any more pipelining or processing difficulties than do their Canadian counterparts was a fundamental part of the survey. The second aim of the sludy was to assess the perceived advantages and disadvantages to the Canadian stakeholders. Producers, pipeliners. upgraders. and refiners were asked for their views on separately regulated. higher water limits for pipeline crude. SURVEY RESULTS The survey contacts were largely chosen on a random basis. although an effort was made to reach American refiners processing higher amounts of water. Most contacts were interviewed by telephone. Approximately 80% of those called were willing to participate. Producers Twelve producers from Western Canada were surveyed by telephone on the quality ofcrude oil they produce, and practices that impact downstream users. The producers were fairly evenly split between heavy oil producers in the Lloydminster area, and producers ofmedium crude in more southerly regions. Producers were, for the most part, well able to treat oil to the 0.5% BS&W standard. Producers reported an average BS&W of 0.35%, with solids ranging from a trace to 60% of the BS&W. Most producers were in favour of relaxing the water limit of pipeline specifications. Even producers who had little dewatering difficulty, said that they could save substantial amounts in demulsifier and fuel gas costs. This is partly due to the fact that the "finishing" aspect of treating exhausts a disproportionally large amount of demulsifier.
Abstract The solubility of carbon dioxide, nitrous oxide, methane and ethane in a physical solvent, triethylene glycol monomethyl ether (TEGMME) were recently measured by Henni and Mather at 40, 70 and 100 ยฐC at pressures up to 10.9 MPa. TEGMME was found to be the best solvent for CO2 removal among physical solvents used in the gas processing industry. In order to compare these solubility data with those of other polar solvents, a literature search was done to gather solubility data in solvents with a wide range of dielelectric constants. The solubility data compiled were for pressures higher than atmospheric pressure. The Peng-Robinson (1976) ISI equation of state was used to correlate the data for the solubility of CO2 in the polar solvents. The Henry's constants are then derived using the Kritchevsky-Kasarnovsky or the Kritchevsky- Illenskaya equation m. The results show that ethyl acetate and propyl acetate are the two solvents that absorb CO2 the most. But, among the best solvents for CO2 removal, TEGMME has the lowest boiling point. Dimethyl ether is among the best solvents for CO2 absorption is also among solvents that absorbs methane the most. Diethyl ether has the highest capacity for methane absorption. The study confirms the fact that the best physical solvents for absorbing acid gases have the disadvantage of absorbing the largest amounts of ethane. The solubility data in the CO2, N2O, CH4 and C2H6 systems were generally well-correlated by the Peng-Robinson equation of state even for those systems that are highly nonideal. Introduction The Government of Canada has been an active participant in the development of international agreements and protocols for emissions reduction. It has committed the country to meeting national emission caps for anthropogenic air emissions. Just how these national targets will be met is a critical question to provincial governments but also to oil, coal and utility companies in Canada. As carbon dioxide is a major contributor to the global warming phenomena, the process of carbon dioxide removal from coal-fired power plants and its utilisation as a flooding agent for enhanced oil recovery (EOR) is the focus of a lot of attention. The CO2 captured will generate revenues and help reduce emissions that contribute to the greenhouse effect. Zawacki et al. (1981) have screened more than 100 solvents for their potential of removing acidic gases (CO2, H2S). The dimethyl ether of tetraethylene glycol (DMETEG) was chosen as one of two most promising solvents. In an attempt to provide the industry with better physical solvents, a study was initiated to test new solvents. Triethylene glycol monomethyl ether [TEGMME, c.A. Registry No. 112-35-6] belongs to the same family as DMETEG but it costs four times less. In order to combine the advantages of both physical and chemical solvents, mixed solvents have been proposed. This combination allows for a higher CO2 loading, a low solution circulation rate and regeneration energy.
- Research Report > Experimental Study (0.55)
- Research Report > New Finding (0.35)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery (0.88)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Corrosion inhibition and management (including H2S and CO2) (0.54)
- Health, Safety, Environment & Sustainability > Health > Noise, chemicals, and other workplace hazards (0.54)
- (2 more...)
Abstract All individuals in a typical oil and gas company require some form of production and operational information to perform their jobs and make timely, effective decisions. Although this data is recognized as a corporate asset, making it available across the company is not a trivial task. Management of this asset has been defined as a significant operational advantage. Wascana Energy has made optimizing data accessibility key element in the initiative to implement SCADA (supervisory control and data acquisition) and production automation systems throughout it's operations. Real time data is captured at the well site and facility level via the SCADA system. To expedite data transfer from the field SCADA hosts to the rest of the corporation, the wide area network (WAN) has been extended to the central facilities in these major fields. Production related data is passed electronically to a field data capture system (FDC) and forwarded directly into the production accounting system. Real time data is continuously available to users through SCADA view nodes. Other selected data is moved from the real time world to static data tables in the operational data store, where it is universally available. Introduction In December of 1995, Wascana Energy Inc..(WEI), as a part of its Re-engineering Process, initiated a corporate wide Automation Project The overall goal of the project was to bring WEI to a high level of automation on an accelerated time frame. The level ofautomation was to be driven by economics. In addition, the Re-engineering process had suggested that there were potential gains to be achieved through the effective management of the information collected by the SCADA system. WHY AUTOMATE? Prior to the kick-off of the corporate Automation Project, WEI had several SCADA applications running within the corporation; however, the Williston Basin Unit (WBU) application, located in Estevan, was the most sophisticated. The Re-engineering Team reviewed or benchmarked several companies, including the WBU application, and determined that several potential benefits could be derived by an aggressive implementation of the SCADA applications. These benefits were grouped into categories - measureable or "hard benfits" which include the following:Production increases of 2% - 30% Reduced power consumption by 11% - 20% Reduced downhole failures by 17% - 44% Reduced surface maintenance/repairs by 5% - 40% Reduced driving/vehicle costs by 31% - 85% Reduced overtime by <65% Reduced contract labour by <36% (as reported by industry). The second category are more difficult to quantify and are referred to as "soft benefits" which can include the following items:Increased field personnel productivity, less driving Faster accessibility to problems (alarms/dispatch systems) More accurate and reliable real-time data, production volumes Faster reporting offield data for analysis/decisions/marketing Increased safety/security/environmental performance Flexibility to respond to time-of-day electricity pricing Flexibility to consider interruptible power service Integrated security/monitoring systems Reduced manual data handling, field paper work Lower stress in the workplace
- North America > Canada > Saskatchewan > Williston Basin (0.99)
- North America > Canada > Manitoba > Williston Basin (0.99)
- North America > Canada > Alberta > Williston Basin (0.99)
Abstract One of the main goals of enhanced oil recovery (EOR) is to achieve maximum oil recovery. The occurrences Of dispersion of miscible displacement cause not to obtain the hundred percent recovery at one pore volume of the injected fluids. This dispersion phenomena is Junction of pore size distribution and the properties of the displacement fluids. In this work different miscible displacement tests has been conducted experimentally on artificial porous media and real porous media (Berea sand-stone). The experimental results show that the shape of S-curve of the miscible displacement are reverse of pore size distribution of the media. The results of the tests are also confirmed by computer modelling. This work shows that the miscible displacement test is a tool to characterize the flow distribution of a porous medium which should be considered in EOR assessment. Introduction The theory of mass transport by dispersion in flow through porous media has become a basic consideration in many scientific and engineering applications. The theory is essential to several disciplines such as chemical, engineering, soil mechanics, geology, and petroleum engineering. Dispersion is of great importance to petroleum engineers, because the phenomenon is incorporated in mathematical models governing the miscible oil recovery processes. these models predict and estimate the rate of miscible injection fluids, as well as predicting the volumetric sweep efficiency of oil reservoir with respect to space and time. Most mathematical models of miscible displacements in porous media are based on the assumed applicability of Fick's Law of molecular diffusion for describing dispersion. The molecular diffusion coefficient of Fick's Law is used to describe the spreading ofa solute as it moves through porous media, but has been relabelled the "dispersion coefficient". This coefficient tends to be the most difficult parameter to determine for miscible flooding models. It has traditionally been assumed to be linearly correlated with the mean flow velocity, with the resultant constant of proportionality termed the dispersivity (Perkins and Johnston, 1963). The dispersivity is believed to be a characteristic of the porous media and, according to Freeze and Cherry (1979), is the most elusive of the solute transport parameters. Despite the practical importance of understanding the dispersion of miscible displacement fluids in reservoir 2oil, there are currently no methods to confidently predict the magnitude of dispersion at a given unstudied chemical oil recovery field. This study was conducted to empirically develop a description of hydrodynamic dispersion in porous media that is independent of the questionable assumption ofapplicability of Fick's Law of molecular diffusion. In order to examine this hypotheses it was necessary to employ a method which would measure dispersion, independent of applying any existing Fickian solute transport model. Hence, the spreading of the miscible displacement breakthrough curve about one pore volume of displacement was used as the measure of dispersion. EXPERIMENTAL APPARATUS The experimental apparatus used for this study was designed to isolate and study dispersion phenomena in relation to flow velocity, porous media properties in one dimension. In order to isolate the dispersion phenomena, several interfering processes had to be eliminated.
- North America > United States (0.22)
- North America > Canada (0.15)
- Research Report > Experimental Study (0.53)
- Research Report > New Finding (0.35)
Abstract The Steam-Assisted Gravity Drainage (SAGD) process, which usually employs horizontal injection and production wells has been applied successfully in producing heavy oil reservoirs. It allows high recoveries to be obtained, at high rates without significant bypass of steam. However, SAGD process. due to, the heat loss to the overburden and adjacent formations can only be used for thick reservoirs with relatively high porosities and oil saturations if there is to be an economic oil/steam ratio. The Vapex process, which uses light hydrocarbon vapours 10 extract heavy oil from the reservoir is studied experimentally in the work described in this paper using a new, longer, scaled, packed model. In the process that evolved from the work. liquid solvent (propane, butane or mixtures) is injected with a small amount of non-condensible gas through a horizontal well at the top of the reservoir to contact and mobilize oil by dilution. The diluted oil is produced by a horizontal well. laterally separated from the injector. and located at the bottom of the reservoir. With this configuration. practical production rates can be achieved without appreciable gas bypass. Solvent is separated easily from the produced liquid by distillation and recycled and this results in relatively low net solvent requirements. Gas fills the vacated pores. The objective of the experiments was to develop process conditions to give high oil production rates with economic solvent requirements. To achieve this major parameters affecting the Vapex performance were investigated: temperature, pressure. solvent injection rates, types of solvent. mixed solvents, well spacing and configurations etc.. The major finding has been that wider lateral well spacings allow higher production rates and make the process more economic. Experimental results indicate that. under suitable conditions. the net solvent injection is about 0.2 B per B of produced oil and that high recoveries and practical rates are achievable. For example. a field prediction based on the experimental data indicates an average oil production rate of450 BID per horizontal well pair. 1000 m long. drilled in a pressure depleted. heavy-oil reservoir that is 10 m thick, to give a recovery of over 50% OOIP for a 70 acre pattern. Introduction The concept of Vapex evolves from the Steam Assisted Gravity Drainage (SAGD) process in which two closely spaced horizontal wells are employed with steam injected from an upper horizontal injector to form a steam chamber in the formation and heated oil drains downwards, driven by gravity, to a horizontal producer located near the base of reservoir. Another form of the process involves the use of multiple vertical injection wells instead of the horizontal injector. In the Vapex process, light hydrocarbon vapours or their mixtures with non-condensible gases are employed instead of steam to extract heavy oil or bitumen from the formation. Compared to thermal processes, the Vapex process can be operated at reservoir temperature with almost no heat loss. Vapex can be used as an alternative to recovery the heavy oil and bitumen from reservoirs which are not suitable for thermal processes such as reservoirs with bottom water and/or high water saturation, vertical fractures, low porosity and low thermal conductivity.
Abstract An interval parameter fuzzy relation analysis (IPFRA) model is proposed for environmental risk assessment of petroleum contaminated acquifers due to leakage from underground storage tanks. The model can effectivelv incorporate effects of different pollutants and different remediation techniques within a general framework. Also. it can directly reflect uncertainties presented as inexact intervals for a number of modelling inputs. Results of a case study indicate that reasonable solutions for risk assessment under different system conditions have been generated Four potential site remediation strategies are analyzed. They have different environmental/economic characteristics with lower risks generally corresponding to higher, costs. Tradeoffs between environmental and economic objectives are then analyzed In general. the JPFRA approach is useful for comprehensively evaluating risks within a system containing many factors with complicated interrelationship. Introduction Development of petroleum industry is one of the major economic sectors in the North America. Its development is currently associated with a number of environmental concerns. Among them, problem of leakage from underground storage tanks (USTs) has been paid significant attention . The number of USTs for petroleum products in the North America was estimated to be between 1.5 and 2 millions. Tejada reported that as much as 23% of all the tanks leak, The main causes of leakage are corrosion (for steel USTs) and breakage (for fiberglass USTs). The leakage problem has led to a variety of impacts, risks and liabilities. It became such an important concern that the U.S. Environmental Protection Agency created the Office of Underground Storage Tanks in 1985. The leakage represents an increasing danger to groundwater resources and public health. Therefore, effective environmental risk assessment of groundwater contamination due to leaking USTs is important for evaluating necessity of site remediation actions and providing support for decisions related to prevention, detection and correction of the leakage and contamination problems. There have been some studies of environmental risk assessment for petroleum waste management. For example, Lo proposed an oil spill risk simulation model based on an probabilistic approach. Hallenbeck and Flowers undertook a study of risk assessment for worker exposure to benzene. Rundmo studied occupational accidents and objective risks on North Sea offshore installations. Generally, most of the previous risk analysts argued that risk should be measured through probability (relative likelihood) of possible contamination and magnitude (seriousness) of consequences from the contamination. Thus, risk could be expressed as a probability distribution over a number of adverse consequences. However, when applied to diverse problems, probability theory often retains a fundamental assumption about the subject area involved. Specifically, it assumes that there exists a historical run for the observations of events. In fact, when attempting to model behaviors of environmental processes, analysts often suffer from a lack of data or imperfect knowledge about the processes. This may frustrate rigorous probabilistic studies. Another problem with the probability theory is its law of excluded middle [p(A โชA) = I] and contradiction [p(A โฉA) = 0]. For instance, rotating a dice, the results will be 6, 5, 4, 3, 2 or I, but never 4.5 or 2.1.
- North America > United States (0.56)
- Europe > United Kingdom > North Sea (0.25)
- Europe > Norway > North Sea (0.25)
- (2 more...)
- Energy > Oil & Gas > Upstream (0.98)
- Government > Regional Government > North America Government > United States Government (0.56)
- Management > Risk Management and Decision-Making > Risk, uncertainty, and risk assessment (1.00)
- Health, Safety, Environment & Sustainability > Environment > Remediation and land reclamation (1.00)
- Data Science & Engineering Analytics > Information Management and Systems > Artificial intelligence (1.00)
Abstract Field experiences have shows that the primary depletion behaviour in several heavy oil reservoirs worldwide is anomalous. It has been theorized that during primary production, the solution gas released from heavy oil does not disengage from the liquid immediately but remains dispersed in the form of micro-bubbles which tends to flow with the oil. Such gas-oil dispersions are termed as foamy oil. Claridge and Prats hypothesised that adherence of asphaltenes to these gas bubbles reduces the viscosity o foil. However, no experimental verification was reported to confirm this hypothesis. Experiments were undertaken to test the above Low Viscosity Model and to obtain and improved understanding of foamy oil rheology. To assess the rheological properties of foamy oil, a series of experiments were conducted using a high pressure rotational viscometer. The effects of asphaltenes, dissolved gas content, temperature, and bubble sizes on apparent viscosity of foamy oil was systematically evaluated. Foamy oil viscosity was found to be independent of shear rate at high pressures. However, a mild non Newtonian behaviour was observed at low pressures. The viscosity of gas-oil dispersion was dependent on bubble size distribution with higher viscosities for smaller size bubbles. The hypothesis of reduced viscosity resulting from adsorption of asphaltenes on surfaces of gas bubbles could not be confirmed experimentally. The viscosity of foamy dispersion was found to be higher than or similar to the live oil viscosity. In addition, the rheological behaviour of dispersions prepared with de-asphalted oils was similar to that of the original crude oil dispersions. This would suggest that asphaltenes do not play a major role in the rheological properties of the dispersion. Introduction Reservoir oil viscosity is the most important parameter that influences the oil recovery process. The higher the oil viscosity, the lower is the ultimate oil recovery. Therefore, it is more difficult to recover heavy oil from the underground reservoirs than the conventional light oil. Reduction of crude oil viscosity using steam, in-situ combustion, and/or solvent forms the basis for most of the EOR processes for heavy oil. Field experiences have shown that the prima depletion behaviour in several heavy oil reservoirs worldwide is anomalous. It has been theorized that during primary production, the solution gas released from heavy oil does not disengage from the liquid immediately but remains dispersed in the form of micro-bubbles which tends to flow with the oil. Such gas-oil dispersions are termed as foamy oil. Claridge and Prats (1995) hypothesized that adherence of asphaltenes to these gas bubbles reduces the viscosity of oil. However, no experimental ve;ification was reported to confirm this hypothesis. In this study, experiments were undertaken to test the above Low Viscosity Model and to obtain an improved understanding of foamy oil rheology. To assess the rheological properties of foamy oil, a series of experiments were conducted using a high pressure rotational viscometer.
Abstract Groundwater is one of the most important resources in living circle and the natural resources in Iran. It has been estimated that the Iranian groundwater resource will he unused for the next ten years if the rate of its contamination by polluted processes will be continued. One of the most important pollution sources of groundwater is leakage of petroleum products from the underground storage tanks. The hydrocarbon leakage appear from the corrosion of tanks and other factors. The hydrocarbon leakages are not only result in pollution of groundwater but also in losses of great amount of sources of energy in IRAN. For the first time. the hydrocarbon storage tanks in IRAN in terms of their dispersion circumstances and their leakages in all of the country is investigated. The existed rules and regulations and the methods of leak detection and technical inspection associated with the underground storage tanks are presented. This study shows that in order to protect the environment and the losses of great amount of energy in IRAN, the organization in charge should pay attention to this issue. Introduction Ground waters are one of the most important sources in living circle and also they are one of the most important natural sources of Iran. Unfortunately in the last few years, these sources which are the most important origin of the consumed sweet water, are severely polluted by guilty proceses. So that the Iranian proficient of the natural sources say. until ten years, if this pollute process continues, these source will be unconsumed. completely. One -of the most important pollution sources of ground waters is leaking of underground storage tanks from petroleum products. This phenomenon appears from corrosion of tanks and other factors. This case not only result In pollution of groundwater but also in losses of great amount of petroleum products being the most important sources of energy in Iran. From 1970s in some of the countries around the world, different works have been done in order to protect the environment. One of these works was the protection of groundwater aquifers. The pollution of groundwater aquifers, are not appear from the eyes and have very intense effects on the human health. In this paper the underground tanks and their dispersion circumstances in Iran are investigated. Also, some methods for leak detection and technical inspection which they are used in Iran and other countries are presented. Situation of Groundwater in The World More than 97%percent of water in the earth is located in the oceans and about 2% in the iced water of poles, so about 99% of total water in the world are not usefully available because sea water is salty and also they have not suitable geographical positions. Table 1 shows that less than 1% of waters in the world are usable, 0.001 % of this water exists as water vapour in atmosphere,0.009%in the lakes of sweet water, and 0.0001 % in rivers and creeks. Groundwater are the most usable water in the world which is 0.1368 %.
- Reservoir Description and Dynamics > Storage Reservoir Engineering (1.00)
- Facilities Design, Construction and Operation > Processing Systems and Design > Tanks and storage systems (1.00)
- Facilities Design, Construction and Operation > Natural Gas Conversion and Storage > Liquified natural gas (LNG) (1.00)