Questions related to Reservoirs
Recognizing depositional sequences is the first step in seismic interpretation for reservoir management. Wu and Hale (2015) presented the “unconformity likelihood” attribute for revealing unconformity surfaces bounding seismic packages so far.
Can anyone please tell me which software program tool I should use to separate unconformities (marked by toplap, onlap, & downlap) on seismic data?
Thanks, and best regards,
I hope this message finds you well. Actually, I have a problem with the irrigation management in SWAT model and I would appreciate if you can consult me on this issue. In my SWAT model I defined the irrigation manually in mgt files using mgt_op=2 and introduced the values of IRR_AMT for each subbasin and HRU and the source of the irrigation one by one based on available data. I have three kinds of irrigation sources which are applied in my model: reach or dam or shallow aquifer. For some subbasins and HRUs (for example hru 1 sub1 or hru6 sub1...) the irrigation is defined to be from the reservoir dam but as I checked the OUTPUT.HRU of the SWAT in these regions some parts of irrigation (varied 20% to 80% for some HRUs) are supplied from the shallow aquifer which the value of SA_IRR (irrigated water from the shallow aquifer) shows that in the output file. It is contradictory that in the theoretical manual is also said as follows: For a given irrigation event, SWAT determines the amount of water available in the source. The amount of water available is compared to the amount of water specified in the irrigation operation. If the amount available is less than the amount specified, SWAT will only apply the available water. (ver2009, p 375) Furthermore, I checked the model with different sources added on by one to debug the problem. If all the irrigation source of a specific subbasin (all HRUs) assumed to be from reach, dam or unlimited source then the SA_IRR (irrigated water from the shallow aquifer) will be zero but if the shallow aquifer introduced as irrigation source for one or more HRUs of a specific subbasin, the other HRUs can also extract the rest of their irrigation water demand from the shallow aquifer as the SA_IRR will be nonzero. It happened for all the other conditions (IRR_SC=1 or RR_SC=2 or 5 According to the analysis of the irrigation source in my SWAT project, I got the following conclusion: If you define shallow aquifer as an irrigation source in one or some of the HRUs of a specific subbasin, then in all of the HRUs of that subbasin, the SWAT model first supplies the water from the defined source (dam or reach) and then it tries to supply the rest from the shallow aquifer. So I would appreciate if you let me know why the rest of the irrigation demands supplied from the shallow aquifer, whereas the reservoir is defined as source location of the irrigation. The output.hru file for one year of running is attached. Please let me know if you need any further information. Thank you for your kind support in advance. Best Regards,
I want to compare the asphaltene deposition amount in reservoir rock (with average) at the different EOR methods by Eclipse reservoir simulator and select the best condition. How I can do it? What are the main keywords for the coding? If you have a sample (Data file) please send it to me.
How do droughts and floods affect reservoir sedimentation and water supply? What are potential sediment management strategies and when they applicable?
How does reservoir sedimentation affect downstream environments and how does the sediment size and shape change downstream?
In anticline structure carbonate Reservoir of areal extension 31x10 km with 24 to26 degrees. no compartments. And no faces alteration (hydraulic continuty exist) multiple Downhole samples, MDT, and well testing samples were taken the bubble point ranging from 2140 psi in one flank to 2746 psi as average.
I am in need of calculation of niche overlap of freshwater fish species in different reservoirs and the calculation method is not clear for me . Can anyone help me to solve this ?
I am interested in any paper addressing the potential environmental effects (positive or negative) of floating photovoltaic systems: in reservoirs, lakes, etc. Any suggestion will be welcome!
I have to sampling phytoplankton and zooplankton for stable isotope analysis to construct reservoir food web.
Can we afford to ignore microscopic details associated with a petroleum reservoir?
1. Having known the complexities associated with the capturing of microscopic details – associated with a petroleum reservoir (such as capturing the details on the packing of grain particles; variations in pore-size distribution; the presence of interstitial clay coatings; the existence of non-uniform wetting surfaces; interfacial and adhesion tensions; contact angles; density and viscosity differences between immiscible fluid phases); how approximate will it be – in order to characterize a petroleum reservoir – by only using – ‘measurable’ ‘macroscopic parameters’ such as porosity, permeability and capillary pressure-saturation behavior of oil-water – in a petroleum reservoir?
2. Do we have any simplified approach – whereby – we will be able to translate the static distribution of oil and water into an equivalent dynamic motion of fluids – in the absence of capturing the microscopic details?
3. How successful are we - in downscaling (and translating) - the macroscopic capillary pressure curves – into an equivalent microscopic-heterogeneities of a reservoir?
4. How accurate the details on (a) the depths of oil-water and oil-gas interfaces; and (b) the shape of water flooding front - will be – typically, deduced from a capillary pressure curve?
5. Can the static capillary pressure (pressure difference between wetting and non-wetting phase) could be treated as a constant – in the absence of oil-water interfaces reaching equilibrium?
6. Any means to translate ‘static capillary pressure’ (which is simply related to the relative saturation of the wetting-phase) into an equivalent ‘dynamic capillary pressure’ (which includes dynamic properties such oil and water flow velocity) associated with the actual dynamic motion of oil and water?
If it depends on fluid velocity, how exactly to take into account (a) the fluid velocity nearer to the injection/production well; and (b) those fluid velocities - as that encountered in inter-well region?
7. Why does ‘Dynamic Capillary Pressure’ remain greater than ‘Static Capillary pressure’ at a given saturation?
A higher Dynamic Capillary Pressure - will always end up with an enhanced ‘water break through time’?
Flow through a Petroleum Reservoir
1. Do we have a ‘dynamical equilibrium’ existing between inertial and viscous forces and those due to external body forces and the internal distribution of fluid pressures – towards defining the velocity distribution – across the (vertical) thickness – associated with ‘Flow through a Petroleum Reservoir’?
If yes, then, why do we have uniform velocity distribution in Petroleum Reservoirs – as against the Parabolic Velocity Distribution (along the vertical section - normal to the flow direction)?
If not, then, how do we characterize the coupled effect of positive pressure (average reservoir pressure) and negative pressure (capillary pressure) responses – simultaneously - associated with a petroleum reservoir?
2. In the absence of an explicit ‘gravity’ (and density) term – in original Darcy’s equation, whether the replacement of ‘hydraulic head’ by ‘pressure head’ remains justified?
3. In the absence of a suction head or a negative head in original Darcy’s equation, can we afford to modify the fundamental physics itself – by bringing in the ‘Capillary Pressure’ – and still get Darcy’s law extended?
Reservoir Engineering / Groundwater Hydrology
Permeability: Can directly be correlated with Porosity?
Having known that ‘Porosity’ remains just as a ratio and does not depend the pore-size explicitly, while ‘Permeability’ explicitly depends on the solid grain sizes and in turn the diameter of the pore sizes;
Under what circumstances, the traditional (existing) correlations between Permeability and Porosity holds good in Sandstone Reservoirs (leaving aside its correlation in Fractured/Carbonate Reservoirs)?
Organic Origin of Oil and Coal: Any similarity found?
In the absence of reservoir conditions - that remain conducive to the dissipation of gas - resulting from leakage from the reservoir,
Will it remain feasible to find the deposits of oil - that are devoid of gas?
If not, which is the dominant factor(s) – that led us to conclude that “both oil and gas have a common origin” and “both oil and gas have been derived from organic reactions”?
In addition, in the absence of oil producing strata - remaining distinctly different from lignitic deposits;
How will we validate the organic origin of oil and gas (apart from considering clays and silts to be the primary sources of organic material) - with reference to the organic origin of coal?
Usually, we open the well at choke size 16/24'' for oil well and 8/24'' for gas well, then we test it at several choke beans untill we find the appropriate size for more production (flowrate) without causing damage into the reservoir.
Now we are looking for a way that can help to predict the suitable size based on the reservoir data.
Recently I have encountered fungal contamination in my cell culture incubator.
I made 1% PSG 2%FBS DMEM for viral infection and 1% PSG 10% FBS DMEM for cell culture, but then the contamination began...
It started with me isolating it to a HEPA filter which had been so oversaturated with water, so much so it was non functional (the previous lab user had tossed the fill line indicator to the back of the water reservoir for the incubator - lovely). So I cleaned the incubator with soap and water, and then applied EtOH to every surface (I know bleach is great, but it corrodes like crazy for copper plated surfaces). I followed the cleaning with a stericycle run. Then lastly I filled the reservoir to the fill line with clean and autoclaved water. I had not yet added the HEPA filter as the replacements hadn't yet come in, and the cell line was growing in a T75 flask with a filter on the cap. But the fungal growth still came back.
In the meantime, I was considering adding an additional 1% Antibiotic-antimycotic to the existing media to nip this in the bud, and growing up the new cell lines in this while awaiting a new HEPA filter.
Is there a reason not to do this? Is it okay for the cells? Help?
For a biological experiment I am trying to calculate at which angle I should set my rocking plate to create a specific flow in my microfluidic chip (gravity driven flow)
I used The Bernoulli equation with frictional head loss (Darcy Weisbach). From the Bernoulli equation I would like to calculate the height difference between my two reservoirs. From this height difference I can calculate the angle.
My Reynolds number is super low namely 3.62*10^-2. Therefore, I wonder whether I am using the right equations. Maybe Bernoulli is not the one?
My calculation bring me to an angle of 0.02 degrees which is practically impossible of course.
P1 + 0,5ρ v1^2 + ρgh1 = P2 + 0,5ρ v2^2 + ρgh2 + fh ρg
With two assumptions:
- P1=P2=Patm because the tank is open, cancells out
- v1=0 as the reservoir is big compared to the channel
This gives me: v2=squareroot(2g(h1-fh))
I want to know h1 so: h1=(0,5v2^2 + fh)/g
Is this the correct equation or should I use another?
I am looking for models like Vollenweider Loading Plots and want to calculate and predict eutrophication in some reservoirs. I have some data about their incoming monthly flows, incoming flows quality, their capacity, and so on.
Could you please introduce me to other models?
Thanks a lot.
Whether the emulsion mud can control leak-off without creating permanent damage, not only with non-productive interval, but also with the pay-zone (reservoir section)?
Which method and which function is suitable to be used to get the target?
1. Productivity of single well at a different location in fractured cave carbonate reservoir
2. Productivity of multiple wells at a favorable location in fractured cave carbonate reservoir
Your help will be highly appreciated
Context: I am simulating temperature stratification in a subtropical reservoir with Delft3D. The heat flux at thewater surface is being calculated with the Ocean model. To calculate the heat flux due to forced convection of sensible heat, the Stanton number is necessary. From different studies, I know that values of 0.00145 to 0.0016 are usual. Now my question is: there is any PHYSICAL upper limit for the Stanton number? would you say a value of 0.0031 is too high?
Thanks in advance.
How to perform sensitivity analysis for dam/reservoir site suitability mapping? if we have considered some parameters (i.e. elevation, slope, distance to the river, geology, geomorphology). So, by using AHP we have done overlay analysis in Arc GIS to develop a suitability map. However, if the dam or reservoir is not constructed, how we can validate the model/resulted maps.
The location of DAM has been obtained by using AHP techniques. As a result, I have prepared the dam/reservoir suitability map. Certainly, validation is a very important part of the model. If, any other dam site is not available/ not constructed in the study area. How can we validate? Is there any method or approach?. Furthermore, Is sensitivity analysis is required for the spatial layers utilized to prepare the dam site suitability map?
I m eagerly waiting for prompt and scientific answers to overcome this difficulty?
Are we really characterizing, a continuous fluid flow of both oil and water - in an oil reservoir - throughout the production cycle (solution gas drive: both black-oil & volatile-oil reservoirs)?
As long as the oil occurs as a continuous phase, a well will produce only oil (as the oil can easily move through the water-saturated reservoir rocks); however, once the oil in the reservoir becomes the discontinuous phase, the well will produce only water:
If yes, why do we require the characterization of an oil reservoir using multi-phase fluid flow (considering both oil & water migration explicitly and simultaneously)?
If not, how will we able to conserve mass and momentum balances in the event of either oil or water (migration) being discontinuous?
Whether the same mass and momentum balance equations applied to oil and water will remain justified for the cases, when
(a) reservoir pressure being greater than bubble-point pressure (producing GOR being equal to initial dissolved GOR);
(b) reservoir pressure being below bubble-point pressure but before reaching critical gas saturation (producing GOR being slightly lesser then the initial dissolved GOR);
(c) reservoir pressure being below bubble-point pressure, but after reaching critical gas saturation (producing GOR increasing steadily)?; &
(d) reservoir pressure being very small, where producing GOR keeps reducing.
Any possibility of oil being found in a finely dispersed state either in (b) or (c) or both - due to in-situ complications?
We are conducting a study with Sentinel-2 data where we are in the need of bathymetry data for validation in shallow freshwater lakes but also dams and reservoirs. We are primarily interested in locations between 60 degrees north and 60 degrees south, especially in South-East Asia, North America and Europe. In terms of countries data from Chile, Turkey, Egypt, Australia, Sri Lanka, Malaysia, Germany and France are interesting. Any suggestions of available data sources are welcome. Thanks in advance.
I am doing a project in the university and I have been asked to do dry hole analysis for some wells in which all data given are seismic and logging data
(1) The magnitude of volume of gas required to move the oil through the reservoir formation to reach the well keeps increasing as the well becomes older. In such cases, if the production gets associated with a water drive, then, how exactly GOR will get influenced?
(2) If the hydrostatic pressure remains greater than the initial rock pressure, then, the GOR will remain as a ‘constant’ throughout the life of the well? Further, if there is no water pressure associated with the reservoir-formation, then, what will happen to GOR?
(3) The rate of decline of GOR with regard to oil production will depend
(a) on the degree to which the well has declined; and
(b) on the difference between rock-pressure and hydrostatic pressure.
Any other sensitive parameter that could possibly influence the rate of decline of GOR?
I'm doing an optimization. The objective function is to maximize the net benefit (Revenue-Cost).I considered the value of sediment that is prevented from entering the reservoir as revenue. I have no idea how to calculate it even approximately!
Could you please help me to find out an approximate value for it?
Water Value: Shadow price of the reservoir water balance equation. Why is it a constant value?
In the book "Managing Energy Risk: An Integrated View on Power and Other Energy Markets" by Markus Burger, it is mentioned is mentioned on page 171 that "Water values stay constant over time unless the reservoir content reaches upper or lower limits".
Why is it that the shadow price of the reservoir water balance equation (water Value) stays constant over time? Why does it change to another constant value only after hitting the upper ot lower reservoir limit?
In comparison, whereas the shadow price of the load balance equation (marginal clear price or locational marginal price) varies from hour to hour, assuming the resolution of the optimization is by hour?
Good afternoon great scholars in the house.
Please I am in need of Toxoplasma gondii Parasite (oocyst/tachyzoite) for a research.
I need assistance on how and where to secure this parasite please
I will appreciate any assistance or recommendations to this effect.
What is the best method for isolationing oocyst from the reservoir host.
I am working on reservoir optimization on the Mahanadi reservoir complex, Chhattisgarh India
currently, I am working on GA PSO, ACO, WOA, GWO, and SA optimization algorithms
After fixing the control parameters and population size of the above algorithms, and running the algorithm every time I get different solutions so how to fix this problem.
I have 31 years of monthly data 12 no of variables.
- I fix the control parameters value and population size based on the previous research but still, I didn't confident, how exactly chosen.
- I am still confused about how to select/decide the number of iteration for optimization problems?
For example, a simple 1D porous flow problem in a reservoir. On the left of the model, there is a production well. So how should I deal with this production well? Adding a Neumann boundary condition at the left? Will it change the physical problem that I am trying to simulate? since if there is a production or injection well, it should be a source term in the mathematical model.
I am currently working with a mature oil field with an average water cut reach 99.5%. The field was developed in the 1970s located onshore with more than 500 wells drilled and 300 active wells.
The reservoir has a very strong bottom water drive aquifer. The reservoir pressure only drops 100-200 psi for 50 years timeframe. Until today, we don't have any injector wells. Thus, the life stage of the reservoir is in the primary recovery state. The recovery factor until today reaches 45% with the "Living with water" production strategy.
Therefore, my question are:
1. How to improve oil production since water injection or gas injection is not an option?
2. Can routine huff and puff surfactant injections for some selected pattern be performed to mimic surfactant/EOR continuous injection?
Thank you in advanced
We want to see the asphaltene deposition in the reservoir rock sample by imaging method, before and after the treatment. at first, we should capture the image of the asphaltene depositions in the mini-plug of rock, and for the other step (the treatment), we need to analyze the same rock sample by imaging. but in this way, we can't use the previous mini-plug of the reservoir rock for treatment. What is your suggestion and idea about this challenge? thanks
National Geographic April 5,2020 article is titled: Tiger tests positive for coronavirus at Bronx Zoo, first known case in the world.
If wild animals, including birds, can be a reservoir hosting COVID-19, that may pose additional hurdles to limiting and containing COVID-19.
Are there reports or studies bearing on this issue?
I am doing some research on seiches and hydrodynamic effects caused by earthquakes in reservoirs, and need some data on oscillation frequency (alongside peak acceleration), to make some simplified models (to start with).
I have found a few sources for acceleration time histories (e.g: https://www.strongmotioncenter.org/index.html), but aside from crudely counting the oscillations per second, the data isn't clearly marked.
I don't mind if the data is recent or historical, I just need a fairly wide range of intensities.
I appreciate anything you can send my way,
TL;DR: Looking for earthquake data that includes how many oscillations occur per second.
- Max (P) = Sum(n*g*p*Q(t)*h(t) for t =1:12
1) The maximum and minimum produced power.
2) The maximum and minimum permissible reservoir height.
3) Hydraulic constraints are defined by the reservoir continuity equation.
4) The maximum and minimum permissible reservoir releases.
5) The maximum and minimum permissible reservoir Storage.
is the number of the production period
Hi. I have data on the mean daily inflow to reservoirs. What is the most common method used in papers to estimate instantaneous peak inflow to reservoirs using this kind of data?
In our different studies for petroleum fluid analysis, we always assume that petroleum reservoirs are isothermal. Do you agree with this assumption? And if not, what is the impact of this assumption on the different calculations related to fluid analysis and consequently reserves calculations?
I am currently working on 2d and 3d seismic survey, after my interpretations I found a good sight for reservoir. My next task is on seismic attribute to probe further. I have been using kingdom software so far anyone with how can go about it. All answers are welcime
After using the sufi-2 to calibrate my data, the simulated data is very much overestimated. the problem is my basin is very large, about 23,124 km2. I did not include dams/reservoirs in my first simulation in ArcSwat since I did not have that information. Now the only information I have about the dams are the dams storage capacity (m3) and annual water abstraction for water treatment from the dams. I want to know, will only these two pieces of information work and will this improve my p-factor and r-factor and R2 values as the first simulations without dams are very poor.
Also, can I improve the p-factor value without including the dams in SWAT?
It is known that the pedosphere is one of the largest reservoirs of organic matter on the planet (up to 2060 ± 215 Pg C). This is significantly more than combined in the atmosphere (~ 800 Pg C) and terrestrial vegetation (~ 500 Pg C). It is also estimated that over 12,000 years of agricultural use, soils have lost an average of 133 Pg (petagrams, 1015 g) C, and the rate of losses has increased significantly over the past 200 years. On the other hand, soil microorganisms respond to rising ambient temperatures by enhanced decomposition of organic matter. Can CO2 emissions from the pedosphere significantly affect the increase in CO2 concentration in the atmosphere and, accordingly, increase its global temperature.
Reservoir Permeability: To be treated as a Tensor?
Although reservoir-permeability may be considered to be varying as a continuous function within the reservoir domain, the variation of reservoir-permeability at the reservoir-boundary may change abruptly and thereby making the permeability distribution to remain as a discontinuous function. In addition, since the permeability of a real reservoir will not only be varying as a function of space but also in direction; the generated angular-difference between the pressure-gradient and the flow-direction necessitates the need to treat the reservoir permeability as a tensor rather than either as a scalar or a vector.
If so, to what extent, are we compromising the estimation of ‘reservoir permeability’ by treating it either as a scalar or a vector instead of treating reservoir permeability as a tensor (having known the difficulty associated in deducing any significant solutions for the tensor relationship)?
I'm experienced in UHV work, but I've recently started using a turbo that hasn't been used in quite awhile, and I'm not sure when the last time the lubricant reservoir was changed. I know Pfeiffer recommends yearly changes for this, but I also know people go beyond this timeframe regularly.
I was curious if there are any signs that the lubricant is reaching end of life (increasing turbo current or shutdowns due to high temp I'd guess) or if you really need to stay on top of that interval to be safe from a catastrophic failure.
GOR Variation in Fractured Carbonate Reservoir: Different from a sandstone reservoir?
Whether the following statements associated with a sandstone reservoir – will also remain true for a fractured carbonate reservoir?
(A) The gas expels oil from the reservoir formation by means of (a) gas carrying oil with it due to its velocity; and (b) gas driving the oil ahead of an expanding volume of gas.
(B) Since the reservoir pressure gets reduced by the earlier completions, the amount of gas required to expel the same quantity of oil would remain greater; and in turn, the enhanced initial GOR for later completions would result only from the drainage of pressure by the earlier wells.
(C) When the gas acts as the only force that expels the oil from the reservoir-formation, then, the rate of decline of oil production would remain faster than the rate of decline of gas production. Also, an enhanced rate of increase of GOR will always have the greatest decline of oil production.
BL Theory in a Fractured Reservoir:
The Buckley-Leverett theory involves two systems which are similar in nature but are differentiated by time; and these systems may be described by the fractional flow and frontal advance equations which essentially characterize the mechanics of oil movement while being expelled from the reservoir.
Is it so in a coupled fracture-matrix system (fractured reservoir)?
Restructuring of complex pore-network and the evolution of reservoir porosity as a function of space and time (to be used in mass conservation equation): Requires the history of reservoir compaction?
If the degree of compaction is neither related to porosity loss nor to the increase in density, then, can’t we apply Athy’s compaction model (which demonstrates the exponential porosity reduction from 50 to 5% over a depth of 2 – 2.5 km from the surface) to characterize the porosity associated with a carbonate reservoir (with dominant cementation, dissolution, pressure-solution, recrystallization & grain-replacement than the siliciclastic deposits)?
Can the linear relation between porosity reduction (with its respective increase in density) and the increased over-burden and tectonic stresses (using Athy’s Model) be applied confidently to characterize a typical oil/gas reservoir?
Whether the compaction associated with a typical petroleum reservoir could result solely from ‘chemical readjustment’ (under any circumstances); or will it always include the reservoir porosity that has resulted from recrystallization of solid grains as well?
If yes, will it be feasible to explicitly measure the enhancement in the rigidity of the solid-grain structure (resulting from the alteration of mechanically deformed clays into shales) to characterize the reservoir porosity?
Note: Approximation is always possible for a normally consolidated sediments of uniform lithology.
Surge-type glaciers exhibit cyclic behavior between long periods of the quiescent phase and shorter periods of the active phase, during which ice surface velocities increase by up to at least an order of magnitude. And during surges, a significant volume of the entire ice mass rapidly transferred from the reservoir to the receiving area, leading to dramatic changes in the surface height and an advance of the glacier terminus often, but not always, takes place, as well as forming newer crevasses and looped moraines. The quiescent phase, surge-type glacier flows slowly, is a period of relative stagnation during which the lower portion of the glacier thins and mass builds up in an upper, reservoir area.
I am reading articles about geochemical parameters in order to know the maturity and the Total Organic Matter Content of the reservoirs, and I realized that exist some differences in the results of Kinetic parameters obtained from Rock-Eval pyrolysis for grain, powder, and kerogen.
As shown in the figure attached, we know the different levels in reservoir for dead zone, live zone and flood zone. Can we not just get the sedimentation in different zones from the survey data itself as compared to previous year survey data.
Influence of Hydrodynamic tilt-factor to Oil, Water & Gas production:
Whether the presence of tilted fluid-fluid (particularly dynamic-OWC and not even GOC) contacts would still ensure the associated ‘rate of strain’ to remain perpendicular to the direction of “resultant” fluid flow (moving with a specific fluid velocity)? In such reservoirs (Sarvak reservoir - Iran), can we comfortably decompose the motion of each fluid element into a pure translation, pure strain (along the principal axes) and a rotation (associated with vorticity)?
Gas Formation Volume Factor (GFVF) as a function of Reservoir Pressure:
Isothermal Compressibility below Bubble-Point (BP) Pressure:
Since the conventional isothermal compressibility on crude oil ‘below BP pressure’ would lead to negative compressibility (as the volume of crude oil mitigates with pressure decline), the shrinkage effect of saturated-oil (variation of oil formation volume factor as a function of reservoir pressure) and the expansion effect of the gas coming out of solution (variation of solution GOR & GVFV as a function of reservoir pressure) needs to be considered explicitly.
If so, can we comfortably estimate the isothermal compressibility of a saturated crude-oil with ‘changing liquid oil composition’, below BP pressure?
Darcy’s-Law; Macroscopic-scale; Experimental parameters measured at a scale that is lesser than macroscopic-scale:
When we characterize a petroleum reservoir with the Darcian approach,
it essentially implies that we are going to replace
the actual ensemble of sand-grains/clay, shale, silt-particles/rock-fragments
that make up the petroleum reservoir by a representative continuum,
we can define macroscopic parameters, such as the reservoir-permeability, and
utilize macroscopic-laws, such as Darcy’s law
in order to provide
the macroscopically averaged descriptions of the microscopic behavior.
If so, can we consider any (laboratory based) parameter
that is measured
at a scale lesser than the macroscopic-scale,
when the reservoir is characterized
using Darcian approach?
Do we have a “homogeneous reservoir formation” in reality - as almost all the reservoir formations display spatial variations in reservoir permeability?
Do we at least have reservoirs that do have variations in reservoir permeability but still maintaining a constant average value of reservoir-permeability through space/volume - so that the concept of “homogeneous reservoir formation” can be justified - at least to some extent?
MEAN (Ave) – SD (Sigma) – Reservoir Heterogeneity:
Given the fact that the probability density function for permeability remains log-normal, leaving aside arithmetic-mean, can a simple geometric-mean or harmonic-mean be used - in order to deduce - the mean value of permeability, while characterizing a heterogeneous petroleum reservoir?
If yes, what will be the value of permeability "at the interface" between two different beds/layers with significantly differing permeability?
If no, should we need to consider the ranges of standard-deviation as well, apart from considering the mean-value of reservoir-permeability, while characterizing the degree of reservoir heterogeneity?
Mean Value of Reservoir Permeability:
How exactly to deduce the average-permeability of a petroleum reservoir with
(a) layered heterogeneity (a vertical cross section having multiple individual beds making up the reservoir formation, each having a homogeneous permeability value of k1, k2, k3, k4, etc.)
(b) discontinuous heterogeneity (caused by the presence of faults and/or large-scale stratigraphic features)?
Reservoir-pressure, Volume of Dissolved Gas & Surface Tension:
While the gas that has been dissolved in the oil (in a saturated reservoir) would cause a significant reduction in viscosity,
will it also cause a significant reduction in surface tension as well – at elevated reservoir pressures?
Mobility of Pore Fluids with Reservoir Deformation:
Does the restructuring of complex reservoir pore-geometry take place during/following the transportation of water, oil & gas towards the production well OR the transportation of these pore-fluids results from the restructuring of the pore-geometry – upon hydrocarbon production? In short, among ‘reservoir-deformation’ and ‘mobility of pore-fluids’, which induces the other?
On a general note, how long will it take for a significant restructuring of the pore-geometry (deformation) to occur in a typical petroleum reservoir?
Will ‘the time period associated with the deformation of reservoir pore geometry’ be comparable with that of ‘the time period required for the migration of water, oil & gas’?
Leaky Petroleum Reservoirs:
Are the confining beds (top & bottom) of a petroleum reservoir are completely impermeable with extremely low-permeability?
Are the vertical flow components remain ‘always’ negligible?
If the confining beds ‘leak’ the fluids ‘either from’ or ‘to the’ reservoir, how exactly the transient radial fluid flow equation would get influenced?
Will it be feasible – in a real field scenario – to distinguish between (a) capture/loss of brine into/from the reservoir; and (b) capture/loss of hydrocarbon fluids into/from the reservoir – resulting from ‘leak’?
Whether the additional data on (a) ‘vertical permeability’ of the reservoir; (b) permeabilities of top & bottom confining units – would suffice – to address the leakance of the confined petroleum reservoir? Or Do we still require more data?
How exactly to distinguish the ‘leakage of fluids into a petroleum reservoir’ from that of ‘production of pore-fluids from a petroleum reservoir resulting from storage effect’?
Pseudo-Steady fluid flow through an oil reservoir: Feasible under special circumstances?
When multi-phase fluid (water, oil and gas) is flowing out of an under-saturated oil reservoir – towards the production well - by primary recovery; and if assume that the same amount of outgoing fluid flux is replaced by an incoming single-phase water-influx from surrounding aquifers that enters the reservoir, in the same time, whether the fluid flow through this petroleum reservoir can be assumed to be flowing under steady-state conditions 'hypothetically'?
Along the spatial length of reservoir between the production-well and the drainage radius, if we hit a point randomly in space, whether the fluid flow can remain as a constant with time – under any given special circumstances (so that the problem can be assumed to be under “simplified” steady-state conditions)?
Will it be feasible - to trace - the path of water, oil and gas particles - as it moves through the reservoir – towards the production well (at the pore-scale)?
During this process, will the instantaneous velocity of the respective water, oil and gas particle’s velocity will remain tangent to the streamline?
Also, will it be feasible to capture the number of streamlines passing through the cross sectional area of the reservoir (per unit area) in a direction – normal to the direction of fluid flow, so that the rate of flow of water, oil and gas can be deduced separately?
I am looking for data (Reservoir characteristics and fluid properties) regarding all the Foam-EOR projects that have been done around the world?
I will be very grateful to you.
Thanks in advance.
How quickly oil wells reach their ‘maximum daily output’ following their completion - associated with a carbonate reservoir?
How different - the rapidity of decline - will be in a carbonate reservoir - from that of a sandstone reservoir?
I am trying to simulate reservoir performance. While COMSOL allows true 1D and 2D problem definitions, does CFX lack because it is 3D dominated?
I would like your opinion from a reservoir simulation perspective where we usually encounter greater aspect ratios between well and reservoir dimensions.
Hi, I'm not that advanced when it comes to remote sensing I'm still learning, would you please help me to find a formula that i can use to calculate Chlorophyll-a Concentration using Landsat 7 and 8, specific, your help will highly be appreciated.
Previously, hydraullic fracturing was used for the development of unconventional reservoirs, however, due to technical problems and environmental flaws this technique was banned in some countries. Researcher are suggesting that liquid nitrogen fracturing can be remedy to that, which provides micro fractures due to sudden thermal shocks, thus, increasing recovery potential. What are you views in this regards? Which technique should be used?
Oil Production Rates:
Having known the fact that the ‘decline rates’ can be measured directly from production data and it remains unaffected resulting from the variations in recoverability, while ‘depletion rates’ depend upon estimates of recoverable resources and it gets influenced significantly resulting from the variations in recoverability:
Whether the observed ‘decline rates’ (the annual reduction in the rate of production from an individual oil-field or a group of oil-fields following a peak in production) in a typical oil field(s) result(s) predominantly from the physical limitation of the production rates; or does it result from ‘under-investment’?
With nearly one-lakh identified oil-fields on the global-scale, are we in a position to precisely correlate (a) the ‘decline rate’ with the ‘depletion rate’ (the rate at which oil is produced in a field or region expressed as a fraction of either URRs or the remaining reserves)?; (b) RRR at a given time as a function of URR & Cumulative-production at that point of time – considering ‘reserve growth’ (time-dependent enhancement in the magnitude of the ‘Estimated URR’)? [In other words, ‘depletion level’ as a fraction of URR?]
Which is more reasonable in a typical oil-field (based on 2P reserve estimates)? (a) Depletion rate of URR; or (b) Depletion rate of RRR?
How sensible will be the ‘decline rate’ (as it is virtually independent of reservoir physical factors that drives the oil depletion, while excluding politics/sabotage)?
How important is the existence of maximum depletion rates preceding the inception of production decline?
Is there an established correlation between ‘depletion-rates @ peak’ with its associated ‘decline rates’?
Will it be feasible to deduce a universal maximum depletion rate that is pertinent to all oil-fields?
Estimation of volume of strata that serves as reservoirs for the oil:
If a reservoir strata has relatively no variation in lithology and thickness over large areas, then, it will remain much easier to estimate the volume of the sand that serves as a reservoir – based on the measurements made on the outc