Petroleum Exploration - Science topic

@Jie Zou, you mean erosion?

Acetate Hot Melt Adhesives. ... EVA is a copolymer adhesive, most commonly used in the paper, packaging, and assembly industries, as they bond to various cellulosic materials and have a wide range of formulations. The composition of the adhesive will directly influence its properties

This is a big and complex topic with many strong opinions. If you are looking for a starting point, you could look at Tyson's 2005 paper in SEPM. Basically, he argued that final TOC in rock is related to 3 factors: organic-matter input, organic-matter preservation, and dilution by mineralic sediment components. So you could answer your question by assessing the relative contributions of OM input, presevation, and dilution. Knowing the context (mineralogy, lithology, depositional environment, diagenesis, etc.) will help you constrain the answer. If tectonics was a significant factor in the source of the sediments, may be it is having a dilution effect on the TOC content? Maybe you can check on the timing of tectonics in Malaysia for a clue of whether it is reasonable that tectonics contributed to greater sedimentation rates, etc.

Yes and no, it all depends on the depth of your question and the scope. If it is a classic source rock evaluation integrated into a larger program that includes petrophysical and basin modelling components , you might get away with it for an initial assesment. However, if your main focus is the holistic evaluation of the source rock potential, you MUST include Organic Petrography (using both transmitted and reflected white light and UV light), as well as sulfur speciation work (the Rock-Eval 7S can now do that and you get differentiation between S2-sulfur and S4 sulfur from that coming from sulfides and sulfates), Pyrolysis-Gas Chromatography (if possible). In addition, if you samples are thermally mature, you need to use a modified pyrolysis program (Shale Play, MHR, Reservoir, etc.), the basic temperature program might not be adequate.

I am not

Dear Abd-Elrahim , I suggest reading this book:

https://www.springer.com/gp/book/9783540853282.

Best regards

Many thanks Al-Mudhafar. I actually did.

Nonrenewable Resources, December 1997, Volume 6, Issue 4, pp 329–337

"Geologic risk, economic assessment, and optimal decision making of petroleum plays in the Bohaiwan Basin, northern China."  This article discusses several statistical approaches and may give you some ideas on how to approach your specific situation.

Hi Michael,, where can I find the source of the empirical equation from Waples, D.W's work? Do you know the name? Thanks!

Here is a link to the article correlating TOC from ell log data.

It is just a correlation based on fairly limited data but if it is all you have and it lets you move forward ith your work go  ahead and use it

Dear friends,

Personally, when I am working on a specific source rock, I first check if Tmax values are increasing regularly with depth, in order to check if the analytical data are dependable. If they are, I correlate Tmax versus R0 and calculate my own equation Tmax f(R0).. The same formula is not valid for all source rocks, but depends upon the type and composition of source rocks

Regards

MLB

Bassey, have you tried using OLGA?

Sde,  My response relates to sub-surface, but I hope that it helps. As far as subsurface measurement go, I am not aware of Ra being specifically measured down hole.  Usual GR spectrum measurements focus on K, Th and Ur as the main contributions to the GR measured signal. K has a single, distinctive, 1.46 MeV decay signature, but Th and Ur have very much more complex decays. The Ur decay includes the Ra group. So Ra is considered as part of what is called the Ur-Ra decay, that makes up the Ur measurement.  Bateman (Open-Hole Log Analysis and Formation Evaluation) has a pretty good explanation of this, if you are interested in how this works. The decay 1/2 life you mention is actually very much more complex.  But the point is that Ra itself is not - normally - measured as part of the GR spectrum logging.

Unconventional sub-basalt imaging and geological interpretation in terms of porosity/permeability in buried volcanic reservoirs in order to extend the life of mature basins in the North Sea.

Dear Hasan!

To determine the prospects of the region with the gravimetric data necessary to know the density of the horizons of both vertically and horizontally. Knowing the distribution of the density using the formulas and paletok can calculate the gravitational effects which can judge about the prospects.

I understand that you are investigating dead or past oil seeps, as detectable at the surface in outcrop, not necessarily exumed oil fields.

On this basis, I suggest to distinguish oil seeps in incoherent terrain and oil seeps in rocks.

Incoherent terrain or soil: the main physical characteristic is presence of some kind of hydrocarbon-related substance, like tar, asphalt, or even wax, concentrated in the soil at the spot of the dead seep. This may also indicate an active seep, possibly with low seepage rate. The main difference would be the absence of gaseous or liquid active seepage in a really dried-up paleo-seep.

Rocks: like-wise, the presence of some  kind of hydrocarbon-related substance, like tar, asphalt, or even wax, at the spot of the dead seep is the main indicator. It would be useful to distinguish seeps in porous rocks (porous and permeable sandstone, porous and permeable calcarenite or grainstone in case of carbonate rock) and naturally fractured rocks (tight clastic rocks, massive limestone or dolomite, without matrix porosity). In porous rocks, the rock in the immediate vicinity of the paleo-seep would be impregnated of heavy hydrocarbons or asphalt/tar, indicating irreducible saturation in the matrix porosity. In naturally fractured rocks, the main sign would be asphalt/tar stain on the walls of the natural fractures where hydrocarbons were seeping out. Again, a live seep can be differentiated from a dried-up seep by the presence of gaseous components and light ends, that are absent in a dead seep.

An oil spill on incoherent soil, even decades old, could be detected by the absence of bio-indicators typical of active oil seeps, because an occasional oil spill is generally not enough to induce the start of a local colony of hydrocarbon-feeding micro-organisms. An oil spill on rock would be easy to detect becouse of lack of deep impregnation in the rock matrix.

Ideally the performance of an EOR method is measured by macroscopic and microscopic displacement efficiency. For macroscopic displacement, the key factor is a mobility ratio between injected fluid and oil less than 1. The parameters related to this will depend on the type of EOR implemented. In miscible processes such as CO2 injection, this is achieved for higher gas viscosity or in the case of CO2 WAG or SWAG, lower relative permeability of the mixture. However, too much water may be detrimental to microscopic displacement. The microscopic displacement is related to interfacial tension and capillary pressure, which will affect the residual oil saturation.

In my research topic, I am running reservoir simulations to calculate mineral dissolution and precipitation in carbonate reservoirs during CO2 WAG injection. When CO2 is injected calcite dissolution happens near the injector and the pH decreases while precipitation occurs downstream. This change in porosity will affect the permeability in long term and may interfere in EOR performance, but I am still investigating this.

Thanks for your answer 

can you send me your e-mail to this adresse for more details 

Sir, thank you for the answer and the paper.

I have a sandstone around and mainly below the tuning thickness. I would test the lateral continuity of the geobodies with a theoretical or empirical thickness vs area function, but I has failed to find one so far. Obviously, there is no simple relationship (host and sand rheologic variations, preexisting deformation zones, etc), but any good range could give me a better understanding of the uncertainties I have.

Thank you very much. I was looking for solution to the problem in producing wells.

Regards

R.P.SONI

This is a full topic by itself, Field Development Planning. 

There are multiple parts of the process: Geology, Petrophysics, Reservoir Engineering, Production Technology, Drilling, Economics, Environmental, Facilities .. etc (The list goes on).

To answer your question regarding the number of wells. I would say you can have 3 approaches. First, it is a gas field, so from P/Z plot and using GIIP for P=0, you can simply define the decline in pressure vs. cumulative production. Now, you know the minimum pressure (BHP/THP and thus reservoir pressure that no production at due to backpressure and thus you find your total estimated recovery). With this approach you need to be careful in case you will have aquifer or over pressure which might result in misleading material balance calculation. Once you got the total recovery, you already have an estimated rate per well per day from your appraisal wells. Then,

total volume recoverable/rate of well *365 (or 360 days based on your assumption*number of years you have the license for/planning to develop the reservoir for) = number of wells required for your field. You should however take into consideration that the lower the draw-down the lower the rate and thus your wells now producing high due to the fact the reservoir is still at initial pressure and by the time it declines, the rate decline as well. Simple Darcy law over different drawdowns and using the P/Z vs. Gp should give you good estimate. You need to take some margin during your estimate of each well rate due to turbulence, well damage, downtime .. etc

Second approach is bench-marking, you should really get pretty good estimate since the field is gas field and thus all you need is to know the total reserves to bench-market it against other fields that were able to produce such amount in certain period of time.

Third approach (which is the the long one) is to start building static model and dynamic model and start increasing the number of wells (try to put one well per drainage area you obtained from your welltest to prevent interference) till you finally have the total number of wells.

If you need a good guide for writing FDP, please send me a message and I will send you something pretty useful.

Good luck; (you might have finished this work already, but I am answering it for people who see the question and/or as a future guide for you).

Jennifer -

As Frank inferred, the US EIA is the correct source for US energy data, but having worked there for about a quarter of a century until my retirement last August, I can tell you that you should look for all metadata you can, and question all assumptions. Modeling, as Paul noted, is always a concern for forecasting, but the relatively short term forecasting you seek here is not nearly so bad as longer term forecasting. However, to this I would add the concern of uncertainty in the input data. I have seen people use models where they implicitly assume 100% accuracy for the input data when there is already likely more inaccuracy there than may be hinted at for the model output! The EIA does publish some technical/statistical notes, and similarly titled appendices to the now online successors to the old printed reports. These documents are pushed into the background as ever more superficial online 'news'-like content seems to fill the EIA webpages, dominated by an office that takes what statisticians produce and then has their nonstatisticians purposely 'dumb it down.' The result is often overstated accuracy, reported by an office that really does not understand the subject matter or statistics. So ... question everything.

On the bright side, for your purposes, although I did not work directly on forecasting very much, it was my impression that the STEO model was fairly well vetted. However, beware of the possibility of bureaucratic mismanagement with the input and/or output. There are too many people involved who really are clueless. Unfortunately, it will not be likely that you can do better elsewhere. The bad influences on the integrity of US EIA data come for the most part from outside sources. Pressure from private industry that is often even less competent is often to blame. Also, management at the EIA has become more and more concerned with timeliness and less and less concerned with accuracy, when it should have been the other way around. Both timeliness and accuracy are necessary to as reasonable a degree as possible of course, but the balance between the two is not good. Often the pressure to produce more than can reasonably be produced is too great. (This reminds me of this adage: "They wanted it in the worst way, and that was how they got it.")

Sometimes you can obtain raw data from the EIA, though much of it is confidential and thus unavailable. Graphical analyses - such as simple scatterplots - that you might do on the least aggregate data you can find might help you to see data limitations to the STEO. However, I am not sure that much such information is available. I worked mostly on sampling and estimation and not in a forecasting office. As for the STEO itself, you may be able to obtain the code and analyze its strengths and weaknesses for yourself.

One forecasting model with which I did work years ago - gone now - tested to me to be way overfitted so that two-month ahead forecasts became less and less accurate as time passed. But my impression of the STEO was that it was not supposed to be so bad, though there has seemed to have been too much tendency to 'adjust' things in some way at the EIA to get what someone thinks they expected to see, and for all I know, that could have happened here also ... so beware.

With current volatilities, I would not expect much accuracy anyway.

Best wishes - Jim 

The PETM can influence the organic material in this boundary and  its quite common in iran at the Top of Pabdeh Formation ,where its also responsible for oil generations in certain oil fields

Hi 

When your drilling pressure is smaller than the pressure of formation, your drilling operation is called underbalanced drilling.

The risk of blow out in this type of drilling is high.

Dear Sadegh,

Maybe these informations will help:

Regards,

Vanessa

For the simple structural traps, the usual practice is to shoot a few 2D seismic lines to delineate the body in space. As these data make use of Two Way Travel Time (TWTT), unless highly refined velocity analysis is available, conversion of time sections into depth sections is a challenging task. However, making use of the well-log information, if the calibration for the producing litho-units is done properly, one can get very reliable information about the hydrocarbon distribution. Vertical Seismic Profiling (VSP) is useful for accurate delineation as it makes use of one-way-travel time. For complex areas, that means, areas having strong tectonic controls like thrust belts, 3D data acquisition is a must. For proper reservoir monitoring when at regular time intervals multi-component seismic studies are carried out, we have 3C4D. These data sets can only help to get very accurate hydrocarbon distribution in space and time.

You might be interested in scanning through the public part of key O&G analysists such as Wood Mackenzie, IHS, etc. While most of their analysis would be made available only to payng custmers, you probably will find some general analysis that should provide interesting orientations.

The following literature may be useful for your research

Abstract; On renewable energy installations such as biogas-, landfill gas- and bio oil engines and even at all kinds of industrial plants lots of waste heat is dissipated into the atmosphere. On the other hand, there is a proven, commercially available technology to convert it (partially) into electricity. This is the Organic Rankine Cycle (ORC), used since several decades within f.i. geothermal plants. Applications of the same technology for waste heat recovery are ratherpremature. To transfer this technology to such applications, practical research in collaboration with

industry was performed with as output : technology review (used working fluids to replace water/steam, expander types...), a market overview, view on technical and economical feasibility, simulation models, comparison between the steam cycle and ORC and selection criteria, industrial case studies (landfill- and biogas engines, steel, glass, paper, automobile, chemical, clay, water cleaning....industry).

As a conclusion, ORC-projects were found being very attractive on renewable energyapplications with the help of green power certificates. On non renewable industrial cases,economic feasibility strongly depends from integration costs and electricity prices.

Ref;Turn waste heat into electricity by using an Organic Rankine Cycle

BrunoVanslambrouck1,, Ignace Vankeirsbilck1,, Sergei Gusev1,, Michel De Paepe2

2nd European Conference on Polygeneration – 30th March-1st April, 2011–

Tarragona, Spain

Can you precise your question? Are you looking into down hole tools only or more generally means to monitor changes in reservoirs? For downhole tools I would list, downhole pressure gauges as the most important change over past 10 years (noting that their impact is somewhat under-rated as implementation is impeded by difficulties in retro fitting) and optic fibers for acousting sensing the most exciting recent development (temperature recording being more established). For surface means of monitoring reservoirs, 4D seismic under all forms is definitely winning the palm if looking at a 10 year span. The fracking massification is widening the seismic field quite a bit. 

Dear Kazeem Alli,

Each Artificial Neural Network (ANN) has a numbers of parameters in forms of weights and biases which are supposed to be effectively optimized in order to response accurately into an input record which can include some numbers representing different affecting parameters on the target.

There are different conventional and modern methods which can be gained to optimize the referred parameters such as Delta rule, Genetic Algorithm and Ant Colony. By the way, nowadays it can be observed that trends of applying modern population based algorithm like Bee Colony and PSO are popularly followed by researchers.

In fact, the PSO and ANN are coupled together so that the PSO acts as a supervisor to optimize the ANN relevant parameter. I and my colleagues have done some papers about application of the mentioned techniques in petroleum engineering which could found in my profile . Then, the optimized forms of PSO-ANN could be applied to predict the supposed parameter.

To answer you question, you need firstly to gather similar data from other likewise reservoir from all over the world, and after that based on the gathered data set you must develop the best structure of the ANN which in this case you can gain from previous literature. Next, it is the turn to optimize the weights and other parameters by gaining from PSO. After finishing all above steps, apply the concluded form of PSO-ANN on some parts of your database known as testing part. If the generated results have a good performance, it is determined by using statistical indices, it has the capability of being applied in your case, for example making prediction of ICV.

If you have any probable question, do not make any hesitation to ask me.

By regards

There is no difference between well, hole, and borehole in a scientific sense. "Hole" is usually used as a shortened form of "borehole." A "well", however, is typically used for extractive purposes, where as a hole or borehole is used for scientific purposes and is not completed for production of any resource.

Offshore oil and gas wells can have several lateral or directional sections drilled from a common vertical section of the well. Each unique lateral or directional section is drilled in a different direction and/or to a different target interval. each of those wells can have unique or related names. This type of well geometry is used where the cost of drilling a new tophole section is higher than drilling multiple laterals.

The ODP and IODP typically drills vertical boreholes for cost and engineering reasons. The drillships used are not typically designed to intentionally drill lateral wells or wells that are significantly deviated from vertical.

Pure water leads to hyponatremia. Salts should

be added. Disclaimer: I'm not a medic.

Here is an article about military water recycling.

No English translation available, but images

have English descriptions, and there are links

to project websites.

According to Sun Tsu, militaires never tell

the full truth.

Regards,

Joachim

Dear Lauren,

I can recommend that you look at the some of the links below.

In short, there has been a lot of activity in South Africa. Major companies are looking to explore and exploit deposits for exmaple, Anadarko, Chevron, Shell, Total, ExxonMobil, BHP-Billiton, Sasol, Cairn, are active in the region.

You can find out more information via the Petroleum Agency of South Africa

Or from Petrosa

RigZone for example is a news agency that reports company operations or activities all over the world.

The Oil ad Gas Journal: http://www.ogj.com/articles/print/volume-101/issue-22/exploration-development/south-africas-east-coast-frontier-offers-untested-mid-to-deepwater-potential.html

The Council for Geoscience also has a lot of information on other resources

Kind Regards, Philip

there are very few (if no) clear evidence of earthquake bigger then 3.6 M triggered by hydrofracturing techniques. Most of bigger induced earthquakes are associated to fluid injection for waste disposal or geothermal energy in area where the crust is already stressed (Ellsworth, Science volume 341, 2013). Said that it is well known since more then 50 years (e.g i suggest you to read the report of a beautiful experiment released to the US environmental protection agency and published in the US geological survey bulletin 1951, by Nicholson&Wesson) that under certain circumstances, the increased pore pressure resulting from fluid injection , whether for waste disposal (usually the most massive injections), secondary recovery, geothermal energy or in that specific case fracking techniques, can trigger small earthquakes and tremors.In most of the case it look like that the fault, although didn't record seismicity in historic times, was already in quasi critical state with stored energy then released by changes in stress or hydrogeological conditions. Basically those experiment indicates that the crust can respond by failing in an earthquake due to human activities such as hydrogeological extraction, fluid disposal and activities associated to non conventional hydrocarbon extraction. In most of the case (not all but debate are still going on as indicated by the recent publication by groups of Zoback, Brodsky and Ellsworth in science and PNRS) the magnitude of the induced seismic event are partly due to the size of any applied stimulation but mainly determined by the strength of the rocks being already stressed. We are speaking about seismicity below the magnitude of 3.5. The extraction/injection experiments registered and investigated (both geothermal, waste disposal and fracking) suggest that the water injection or extraction stimulation are the main effects that take the ambient stress within rocks beyond the yield point of the rock. The majority of the case where reasonable induced earthquakes (bigger then magnitude 3) . has been measured suggest that fluid injection associated to huge waste disposal in tectonically stressed area is the most probable effect. As an example take what happened in the Lancashire near Blackpool . We know from historical description that Lancashire region has been affected in the 1835 by earthquake of presumably magnitude 4.4 and not much happened or has been recorded since then. Suddenly a series of microseismic events in between April and June 2004 were detected also by the local population. There is agreement between the scientific community that the hydrofracture process (fracking) carried out at Preese Hall (Lancashire) was the trigger of the sequence of minor seismics events near Blackpool on april -June 2011 (max magnitude 2.4). But in that case it is now clear that the state of stress which was released by these events was pre-existing and the hydraulic changes made in hydrofracturing were simply the perturbation which initiated the sequences of events. Similar sequences are reported in Holland (near the Groningen field, where most of the earthquake are induced by hydrocarbon/gas exploration) and in Oklahoma. In all these case the difficulty derive from the lack of precise stress, pore pressure and seismicity data (before the injection experiment) in area where exploration or fluid injection are in due course. Similar conclusions have been reported by Van der elst (science, vol 364,p164, 2013) looking at fluid injection site in the Middlewest of the States and by Ellsworth (science, vol 341, 2013, Injection induced Earthquakes) reporting an overview of the recent experiments analyzed.

Basin modeling based on the burial thermal history ,and determination of lithology for each formation overburied the source rocks and vitrinite reflectance ,and other agents could enable to setup model to indicate transformation ratio that declare the time and extent of oil generation and increasing of tempreature accordingly .

It sounds like you are interested in modeling the potential impacts. Have a look at Carriger and Barron (2011). They suggest using probabilistic models. Their publication can be found here: