Petroleum Geology - Science topic

Hi, very nice question!

If you want to test different scenarios, depending on the scale you work on, vitrine reflectance in OM rich layers combined with a basin modelling analysis can help you to reconstruct the thermal history of a sedimentary unit.

Best,

Dear Xin Liu, China University of Petroleum - Beijing.

I recommend using the magnetic anomalies to estimate the Curie boundary, which indicates, direct or by analogy, the distribution of the thermal anomalies, present-day heat-flow, providing a clear marker for the thermodynamic effect in the crust and mantle. Therefore, I recommend first the use of magnetic anomalies, for example, from the EMAG2 datasets, it is free, and it has the wavelength (deep mantle large-scale structure) that you need in your research.

The knowledge of the magnetic anomalies in LIP (large igneous provinces) regions is a geophysical way, due that the mafic and ultramafic intrusions linked to those LIPs and their contrast in magnetic properties, magnetic susceptibility, using modeling and inversion.

Also, high densities contrast mafic/ultramafic rock compatible with serpentinized, also could show you in gravity anomaly inspection of a LIP, particularly regarding Bouguer complete anomaly map / Residual isostatic anomaly map.

I attached Jennifer Blanchard´s Marter of Science thesis, "Geophysical identification and characterization of mafic-ultramafic intrusions in plume centre regions", 2015, Carleton University, Ottawa, Ontario, Canada. I recommend reading in focus the Modeling methodology, it has wonderful examples.

Best regards, Mario E. Sigismondi

Carbonate mineralisation can be used to track thermal histories, utilising U-Pb geochronology (giving you time), in combination with clumped isotopes (giving you temperature).

These papers combine these two methods (and there are many others utilising the methods individually):

Mangenot, X., Gasparrini, M., Gerdes, A., Bonifacie, M. and Rouchon, V., 2018. An emerging thermochronometer for carbonate-bearing rocks:∆ 47/(U-Pb). Geology, 46(12), pp.1067-1070.

Pagel, M., Bonifacie, M., Schneider, D.A., Gautheron, C., Brigaud, B., Calmels, D., Cros, A., Saint-Bezar, B., Landrein, P., Sutcliffe, C. and Davis, D., 2018. Improving paleohydrological and diagenetic reconstructions in calcite veins and breccia of a sedimentary basin by combining Δ47 temperature, δ18Owater and U-Pb age. Chemical Geology, 481, pp.1-17.

Brigaud, B., Bonifacie, M., Pagel, M., Blaise, T., Calmels, D., Haurine, F. and Landrein, P., 2020. Past hot fluid flows in limestones detected by Δ47–(U-Pb) and not recorded by other geothermometers. Geology, 48(9), pp.851-856.

MacDonald, J.M., Faithfull, J.W., Roberts, N.M.W., Davies, A.J., Holdsworth, C.M., Newton, M., Williamson, S., Boyce, A. and John, C.M., 2019. Clumped-isotope palaeothermometry and LA-ICP-MS U–Pb dating of lava-pile hydrothermal calcite veins. Contributions to Mineralogy and Petrology, 174(7), pp.1-15.

Looser, N., Madritsch, H., Guillong, M., Laurent, O., Wohlwend, S. and Bernasconi, S.M., 2021. Absolute Age and Temperature Constraints on Deformation Along the Basal Décollement of the Jura Fold‐and‐Thrust Belt From Carbonate U‐Pb Dating and Clumped Isotopes. Tectonics, 40(3), p.e2020TC006439.

Pan, L., Shen, A., Zhao, J.X., Hu, A., Hao, Y., Liang, F., Feng, Y., Wang, X. and Jiang, L., 2020. LA-ICP-MS U-Pb geochronology and clumped isotope constraints on the formation and evolution of an ancient dolomite reservoir: The Middle Permian of northwest Sichuan Basin (SW China). Sedimentary Geology, 407, p.105728.

Hoareau, G., Crognier, N., Lacroix, B., Aubourg, C., Roberts, N.M., Niemi, N., Branellec, M., Beaudoin, N. and Ruiz, I.S., 2021. Combination of Δ47 and U-Pb dating in tectonic calcite veins unravel the last pulses related to the Pyrenean Shortening (Spain). Earth and Planetary Science Letters, 553, p.116636.

Dear Mr. Daoud,

just this type was investigated in the cited paper:

DILL, H.G., BERNER, Z., KAUFHOLD, S., WEBER, B. and METZ, U. (2013) Facies-related baryte mineralization bearing Cu-Zn sulfides in Miocene estuarine deposits of the upper Rhein Graben (Wetterau, Central Germany).- Sedimentary Geology, 296: 55-71.

Abstract: Abstract

Baryte with or without base metal sulfides is quite common in sediments deposited in open marine environments or in continental sedimentary basins. Its precipitation is caused by hydrothermal processes, related to diagenesis, and frequently mediated by biogenic processes. The current study is focused on siliciclastic sandstones of Miocene (Aquitanian) age in an estuarine environment in the Wetterau region of the Rhein Graben, central Germany. In the estuarine environment only the central basin and the landward delta are host to a diagenetic and subsequent hydrothermal mineralization.

Diagenesis took place under near-ambient ( T ≈ 25°C) conditions and resulted in strong pyritization (-0.75 <Eh < +0.25, pH >5) in the central basin. Diagenesis is more landward represented by a pervasive silicification (pH < 12) in deltaic sandstones.

Epigenetic mineralization (100°-130°C) with pyrite in the central basins was succeeded by Cu-Zn-(Sb) minerals (0.75 < Eh < 0 / 5 < pH < 11), silicification and kaolinisation (2< pH < 9.5) and eventually by the formation of gibbsite (3 <pH<8). At the transition from the delta to the estuarine funnel, baryte is of very widespread occurrence. Its variegated texture and crystal morphology allow for a precise determination of the hydraulic system as marine phreatic, freshwater phreatic, and freshwater vadose. The narrow size of the rift graben and its sealing against the open sea fostered concentration of Ba and enhanced the redox processes. Hypogene brines along with Miocene volcanic activity provided the metals, and marine ingressions in this transitional environment supplied the sulfur. Sulfides were concentrated in the finer-grained rocks because of their enrichment in organic material, while sulfates accumulated in the more permeable coarser sandstones.

H.G.D.

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

Dear Sara, During the 1990s I was among a group of geoscientists working in the former Soviet Union who produced a book called "Russian Style Formation Evaluation", which was published jointly by the London Petrophysical Society and the Geological Society of London. It was a guide to using Soviet-style well logs. It in now out-of-print, and available second-hand on-line but quite expensive, although you may find it in a library. I've worked a lot with Soviet-style logs, but on a commercial basis so no papers published I'm afraid. Regards, Graham

Hi There! You should try the Andino, one of the most powerful modeling softwares, and it is available in full for free academic use,

info@lateandes.com

The best and easiest book is AAPG ASQUITH and Gibson book full of charts and log interpretation. It is recommended for reading and applications

There is a sample of limestone with skeletons of clams and corals with patches of bitumen in between. When you hit this rock with a hammer you get the smell of gasoline.

The fossils are the remains of sea animals while bitumen the remains of the soft parts of the animals.

How anyone could think that oil and gas are not the remains of pre-existing life?

Thank you so much. Will check that.

See diapir influence on Cambrian reefs in Geological setting of the Moorowie Formation, lower Cambrian ...

and the chapter on the Frome Diapir minibasin (adjacent to Moorowie) in:

Thank you, Mr Guandalini, surly your experience and research will be helpful to me and other beginners in this field of science.

Jamal:

Have a look at this link for essential insights:

Best

Syed

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

You may also look at the attached SPE Distinguished Lecture about the upgridding and upscalling.

RPH tools List of Matlab files The Rock Physics Handbook, 2nd Edition,Mavko,Mukerji, and Dvorkin, also QSItools another Matlab list with rock physics templates.

You can try using Pimpedance vs Vp/Vs and color code with Gas hydrate saturation I  think these files can help you.

I hope that it will help you.

best regards

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

The paper I sent you has a direct reference to Shaqlawa. Hope the reference is useful, Tiago

Dear Matteo,

I think that the answer to your first question is yes. The gas hydrate layer forms a self generating near surface seal that can trap free gas below it.  There is a large body of Russian literature on the subject of gas hydrates in Siberia and it appears that the methane is mostly biogenic in origin.

See:-

Skorobogatov, V.A., Yakushev, V.S. and Chuvilin, E.M., 1998. Sources of natural gas within permafrost; North-West Siberia. In Permafrost Proceedings Seventh International Conference, Collection Nordicana (Vol. 57, pp. 1001-1007).

and also:-

Collett, T.S., Lee, M.W., Agena, W.F., Miller, J.J., Lewis, K.A., Zyrianova, M.V., Boswell, R. and Inks, T.L., 2011. Permafrost-associated natural gas hydrate occurrences on the Alaska North Slope. Marine and Petroleum Geology, 28(2), pp.279-294.

With regards to your second question on subsurface identification of free gas, this is the classic shallow gas drilling hazard problem.  Good quality high frequency shallow seismic to identify the low velocity zone associated with the presence of free gas are a requirement.  The key metric of vertical seismic resolution to observe the free gas zone can be an issue. I have observed horizontal near seabed flat spots on deep water marine 3D seismic in the South Atlantic in areas where porous strata are deformed to near vertical by allochthonous salt diapirs.  The vertical geometry of the disturbed beds permits easy identification of the seabed gas hydrate zone and its associated free gas flatspot.

Dear Willen: I'm subscribed to the blog Geology Page, and just received an article regarding fractioning of trace elements in basaltic MORB magmas, which could offer an answer to your problem and questions. This is the link:

The conclusion is quite ingenious, you'll love it! Regards, Sebastian.

Mr. Ezzine,

My co-worker recently attended a training workshop put on by TOPCORP and a few companies were mentioned. I cannot vouch for any as i have not worked with or heard about the work ethic but figured it may give you a starting point.

I know that the Marcellus shale producers in Pennsylvania have gone to a regionally centralized recycling center system for multiple company use.

Cheers and good luck!

Francois-Xavier

Have you got any further with resolving this problem? I think that it is a case of converting a geographic to mathematic coordinate system, therefore if the coordinates are converted to local datum it might work, it has worked for one of my models so far but failed with a few too!!

This is a good start

The Biomarker Guide, 2nd Edition. I. Biomarkers and Isotopes in the Environment and Human History

Peters, K. K., Walters, C. C., Moldowan, J. M.

Cambridge University Press, 471 pages. 2005

Yes, It has an essential role. For example, the angle of discontinuity in rock can be increase or decrease the UCS and elastic modulus.

Sorry, I just saw this question.

GMD bhai I have no idea about shale gas.

Hi,

this may happen for dense cohesionless soil or overconsolidated cohesive soil, which might be present e.g. in glacial terrain. The pore volume of these types of soil may increase under shear loading at dry or drained conditions, that is, these soils may dilate. However, if you have locally undrained conditions, the tendency to dilate causes negative excess pore water pressure (underpressure), which in turn results in a total pore pressure less than hydrostatic.

Regards

Almost all advantages and disadvantges of using glass-disks or pellets are mentionned in the various comments. But one important observation is missing, that is specific to X rays: the matrix effect, that is the variable auto-absortion of X rays by samples irradiated for analysis, glass-disk or pellets.

Glass disks: the amount of sample in the glass is low (dilution). The matix effect is buffered by the melting reagent. It is even recommended that the dilution is high. It is even recommended to add an heavy absorber (ie: La oxyde) to reach a better buffering . In other words, the contribution of the matrix effect of the sample in the glass disk is neglible with respect to the over-all matrix effect of the glass disk. The intensity of emitted X rays is directly proportionnal to the concentration of the element in the glass disk. No correction needed. This method can be used for major and minor elements which support the lowering of emission due to the dilution and / or to the heavy absorber.

Plellets: to be used for trace elements whose intensities of emitted X rays do not support the buffering technique above. But it does need the appropriate corrections for the matrix effect of the sample. The auto absorption by a basalt is twice larger than that by a granite ! The matrix effect of a pellet can be accurately calculated from its major element composition that can be obtained through the glass disk method above.

Pellets, background correction. Correcting for the matrix effect is of course an absolute necessity. In addition to this correction, the determination of the background needs a specific care. The backgroung is an image of the background of the X ray tube irradiating the sample. This image is made through the elastic / inelastic "reflexion" of photons from the X ray tube to the detector. This "reflexion" is function itself of the matrix effect of the pellet. In addition to this observation, the X ray tube may contain a ray (weak but can be of importance for trace element determinations) whose wavelengh cannot be separated from the emitted ray by the trace element involved. This correction, as well, can accurately be accounted for.

We run a Van XRF Laboratory on board the Glomar Challenger (DSDP, Deep Sea Drilling Project) from 1974 to the mid eighties, initially for major element determinations and then for both major and trace element measurements. The stategy of Leg 82 of DSDP relied on shipboard trace element determinations (Nb, Zr, as "equivalent" of La and Sm). Details can be found in the Initial reports of DSDP (ie: Leg 37, Leg 82).

some references:

Bougault, H. and P. Cambon (1973). "Dispersive X-ray fluorescence analysis on board oceanographic vessel." Marine Geology: 37-41.

Bougault, H., P. Cambon, et al. (1977). "X-Ray spectrometric analysis of trace elements in rocks. Correction for instrumental interferences." X-Ray Spectrometry 6: 66-72.

Bougault, H. (1980). Contribution des éléments de transition à la compréhension de la génèse des basaltes océaniques. Analyse des éléments-traces dans les roches par spectrométrie de fluorescence X. Paris, Paris VII, France: 221 (in french)

Etoubleau, J., H. Bougault, et al. (1985). Analysis of Trace Elements in Basalts by Shipboard X-Ray Fluorescence Spectrometry: a Discussion of Niobium. Initial Reports of the Deep Sea Drilling Project. H. Bougault and S. C. Cande. Washington, U.S. Govt. Printing Office. 82: 35-43.

UPDATE - for those following this question, the two most relevant papers I have found so far are:

(1) Burruss, R.C. and Laughrey, C.D., 2010. Carbon and hydrogen isotopic reversals in deep basin gas: Evidence for limits to the stability of hydrocarbons. Organic Geochemistry, 41(12), pp.1285-1296.

(2) Gao, L., Schimmelmann, A., Tang, Y. and Mastalerz, M., 2014. Isotope rollover in shale gas observed in laboratory pyrolysis experiments: Insight to the role of water in thermogenesis of mature gas. Organic Geochemistry, 68, pp.95-106.

If anyone knows of other relevant papers, please let me know. Thanks, Jim

What is FCC?

Dear Fahd,

I have done a large (80 well) regional study of pore pressures and present-day stresses in the Nile Delta. However, unfortunately, I have only so far only published the results on present-day stress orientations and some brief comments on stress regimes. However, I have done a bit of work on the overpressure origins, as well as compiled a number of papers and theses on overpressure in the Nile that will be useful.

On overpressure origins, it is correct that the primary overpressure generation mechanism is disequilibrium compaction (as expected – high deposition rates and fine grained sequences). However, porosity-vertical effective stress analysis also shows some evidence for additional components of overpressure generated by fluid expansion (likely gas generation, a clay diagenesis influence or vertical transfer).

I have too much information to really share here. I will put some references below, but it may be easier if you contact me by e-mail (mark.tingay@adelaide.edu.au) – I can set up a dropbox link with these papers and some other information for you.

Might I also suggest that you join and ask this question on the Overpressure and Pore Pressure Prediction group on Linked In - you might get more information from the 2600+ people in that group!

Nashaat, M. (1992). "Geopressure and geothermal studies in the Nile Delta, Egypt." M.Sc thesis, faculty of science, Al Azhar University, Cairo: 133.

Nashaat, M. (1998). "Abnormally high formation pressure and seal impacts on hydrocarbon accumulations in the Nile Delta and North Sinai basins, Egypt." AAPG Memoir 70: 161-180.

Andreoletti, C., N. Bienati, et al. (2009). "Integrated approach to imaging and pore pressure prediction in the Nile Delta." International Petroleum Technology Conference held in Doha, Qatar: 1-6.

Badri, M. A., C. Sayers, et al. (2001). "Pore pressure prediction data using seismic velocities and log data in the offshore Nile delta, Egypt." 2001 SPE Middle East Oil Show held in Bahrain: 1-7.

Shaaban, F., R. Lutz, et al. (2006). "Source-rock evaluation and basin modelling in NE Egypt (NE Nile delts and northern Sinai)." Journal of petroleum geology 29(2): 105-124.

Heppard, P. D. and M. O. Traugott (1998). "Use of seal, structural, and centroid information in pore pressure prediction." Amoco Exploration and Production Technology Group, Houston, Texas.

Tingay, M., Bentham, P., De Feyter, A. & Kellner, A., 2012. Evidence for non-Andersonian faulting above evaporites in the Nile Delta. In: Healy, D., Butler, R.W.H., Shipton, Z.K. & Sibson, R.H. (eds.) Faulting, Fracturing and Igneous Intrusion in the Earth's Crust. Geological Society of London Special Publication, London, 367, 155-170.

Tingay, M., Bentham, P., De Feyter, A. & Kellner, A., 2011. Present-day stress field rotations associated with evaporites in the offshore Nile Delta. GSA Bulletin, 123, 1171-1180.

Hi Matteo

Please, check Marfurt and Alves (2015). Pitfalls and limitations in seismic attribute interpretation of tectonic features. Interpretation.  Most interpretation pitfalls occur by not paying attention to structural deep, subsidence, etc., as pointed out in Cartwright and Santamaria. The paper is open access, so feel free to divulge it.

Dear Oladotun

You can use this formula for getting Bottom Hole Temperature:

GD = (BHT-ST)/TD

that GD is geothermal gradient, BHT is bottom hole temperature, ST is surface temperature and TD is total depth of borehole.

If your 4 wells are in the same basin you can use geothermal gradient maps for getting GD or also can use other wells to calculating a roughly measure of GD. By knowing the GD you can use the above mentioned formula to calculating BHT.

All Regards. 

This depends, to some extent, on the analytical method used. However, whether using ICP or XRF for whole-rock, the equipment should be calibrated using recognized standards. The most commonly and accepted ones for internal calibration (basalt - andesite are the USGS standards - these include BHVO-2, BIR-1, AGV-2. See summary at attached url:

and

DTS-2B is a dunite which would extend the Mg calibration, but this one is less commonly used.

If the equipment is calibrated using these, then the calibration lines should be reliable within the limits of the range of element compositions that these samples exhibit. For instance if the Mg is calibrated with standard samples ranging from 8 - 20% MgO (e.g., basalt to komatiite composition), then any unknown sample lying between these values should lie on the calibration, and thus be an accurate determination. If element concentrations lie beyond the calibration limits (for any element), then the error increases the further the unknown sample concentration lies beyond these 'calibration values'.

The best option is to request the standard suite list from your analytical lab, and determine whether your samples fit into their 'calibration limits'.

Good luck.

Dear Patrick 

The fluid column can be more complicated than conventional reservoirs. Here are some possibilities:

  1. bitumen with or without bottom water

  2. top water over bitumen with or without bottom water

  3. gas over bitumen with or without bottom water

  4. gas over top water over bitumen with or without bottom water

  5. any of the above with gas distributed unevenly in the main bitumen zone.

The oil sands of Alberta appear to be an easy task for a petrophysicist. After all, the sands are pretty clean, quite porous, and the fluid properties are reasonably well known. Even a novice geologist should be able to do it. However, a series of forensic log analyses over the last 30 years or so suggest that there are some basic misunderstandings about how oil sand cores are analyzed and how to calibrate log analysis results to that data.

DEAN-STARK CORE ANALYSIS METHOD

This method is used in poorly consolidated rocks such as oil sands and involves disaggregating the samples and weighing their constituent components. Samples are usually frozen or wrapped in plastic to preserve the contents during transport.

                                             Dean-Stark laboratory apparatus ==>

In the lab, the still frozen cores are slabbed for photography and description, then samples are selected and weighed.

Samples are then heated and crumbled to drive off water, and weighed again. The weight loss gives the water weight. Solvents are used to remove oil. The sample is weighed again and the weight loss is the weight of oil. The matrix rock is separated into clay and mineral components by flotation, dried and weighed again, giving the weight of clay and weight of the mineral grains.

      1: WTwtr = WTsample - WTheated

      2: WToil = WTheated - WTminerals&clay

By dividing each weight by its respective density and adjusting each result for the total weight of the sample, the volume fraction of each is obtained. Porosity is the sum of water plus oil volume fractions  Because the bound water in the clay is driven off by the drying sequences, this porosity is the total porosity.

      3: VOLwtr = WTwtr / DENSwtr / WTsample

      4: VOLtar = WTtar / DENStar / WTsample

      5: PHIcore = VOLwtr + VOLtar

Moreover the bulk density was estimated previously by Clerk (1957) you can find his work in link below:

link: http://www.ags.gov.ab.ca/publications/INF/PDF/INF_022.pdf

Chorpa (2010) have discussed about density of fluid  tar sand type

link: https://books.google.de/books?id=Y1-gwOIw3h4C&pg=PA16&lpg=PA16&dq=Tar+sand+fluid+density+measuring&source=bl&ots=39YeKKI_G_&sig=s-7wDqnU1k5jsYOe_b7oJvTQfLI&hl=en&sa=X&ved=0CFYQ6AEwCWoVChMI1-3f1tm0xwIVAj8UCh3LaQge#v=onepage&q=Tar%20sand%20fluid%20density%20measuring&f=false

Speight (2013) explained Classes of Fluids which presented fluid charactristcs in reservoir 

link: https://books.google.de/books?id=_bxAAQAAQBAJ&pg=PA66&lpg=PA66&dq=Tar+sand+fluid+density&source=bl&ots=ZTGzpfjtj-&sig=RLYezkoCd6J8cNvrvhz-id3mRIM&hl=en&sa=X&ved=0CCYQ6AEwADgKahUKEwi727Gq27THAhXLPhQKHSbEDNo#v=onepage&q=Tar%20sand%20fluid%20density&f=false

Work of Speight is a completely discussion on the habitat of fluids of reservoir.

 Greaves and Bentaher (2006) studied on characteristic of some fluids (Heavy oil, Tar sand and etc)

link: http://www.helgroup.de/articles/pdf/d9b2fa8882246366/Oil%20Recovery%20Tests.pdf

Regards

Massih

Thank you Khaldoon for your help. I will ask them.

You said "...by using Seisee the profile looks just fine..." so why don't you use Seisee to update the headers?   Just type your location data into the desired columns and save!!!

Ioan

Many thanks. This looks like an excellent database. I may have some more questions  for you when I have had a good search.

Best wishes and thanks again.

Jana

openFOAM I believe..

What do you call Heavy Oil? Usually people define HO function of a viscosity threshold which is strongly but not strictly correlated to viscosity; downhole viscosity is the real discriminator for HO in-situ recovery processes - reservoir temperature is a key element, it is one of the key technical element that determine that the Orinoco belt is today a "cold" province and Athabasca a thermal one. I exclude mining, altogether another issue. Function of the viscosity threshold you will get two answers. With a low viscosity definition the answer is "solution gas drive". With a high cutoff the answer is "thermal method". Amalgamating the two is truly mixing apple and oranges. I would place the boundary around a few 10 000 Cp. CHOPS, polymer (including ASP), hot water are not contenders today for universality but competitors in the lower viscosity domain. I doubt CHOPS will be "universal", upon maturing polymer floood might get there. Variants of SAGD and CSS are contenders for pure version of those processes in the high viscosity domain but immature today.

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

Dear Sadegh,

Maybe these informations will help:

Regards,

Vanessa

Managed pressure drilling for the system when the flow from the well is not specifically set off during drilling, but the pressure profile in the well is precisely controlled using closed and under high pressure drill fluid recirculation system. Not relying only on the hydrostatic drilling fluid column, managed pressure drilling systems regulate the wellbore pressure through the instrumentality of revolving head of blow-out preventer with ground monitoring system of pressure of returning from the annulus mud.

During underbalanced drilling the emphasis is on protection of reservoirs from damage especially in depleted reservoirs with low pore pressure. Causing a fluid influx from the reservoir during drilling, we prevent the skin- effect and consequence negative impact on well productivity and reservoir return. Under pressure in the wellbore also increases the penetration rate, lengthens life of bit and prevents drilling mud loss into the reservoir, thus minimizing the probability of differential pressure sticking.

Pressure control during the drilling process - an advanced form of primary well control designed to prevent downtime and costs of non-productive time involved in traditional methods of drilling. The most common variants of pressure control during drilling provide an opportunity for using closed mud returns system and a system, which can withstand high pressure. Last-mentioned allows, in turn, more precisely controlling the pressure profile around the wellbore.

The advantage of pressure control during drilling should be considered also the ability to adjust the bottom hole pressure with minimal interruption of the drilling operations. Unlike underbalanced drilling, which main purpose is to increase well productivity by minimizing the risk of productive areas damage, the main purpose of the pressure control technology during the drilling process is decreasing its value. Presence of zones with diminished pore pressure, overpressure, and areas with not large pressure margins (pore pressure and fracturing pressure are same) can lead to drilling cost increase. When using conventional drilling techniques solution of drilling problems resides in another casing landing, weighting up mud, if not a cancel of the drilling project. In conventional drilling bottom hole pressure is determined solely by mud weight, hydrostatic pressure and dynamic friction component sum. In this case, the only bottom-hole pressure stimulation method without stopping drilling and changing the basic mud weight - is on and off switching of mud pumps. A significant number of problems associated with drilling (and, consequently, with the working hours without bottom-hole deepening), currently facing the offshore drilling industry, may be to some extent solved by forming-up more accurate wellbore pressure control technology. Long-term interruptions of drilling are not required in this case.

Dear Dr El Nady,

Organic Geochemistry in a simple sense is the study of the chemical components of any organic materials that might have decomposed under certain geological conditions/processes to become hydrocarbons (gas, condensate or oil).

Petroleum Geology again in a simple sense is a Geological Setting (usually basins) on a regional scale where it is most likely to generate & accumulate hydrocarbons. There are at least some critical geological factors (source, maturity, migration, reservoir, seal, trap) that one has to asses for any basins if they worth prospecting for.

Both Petroleum Geology & Organic Geochemistry go hand-in-hand if you want to understand the whole petroleum system of a basin.

Regards

shadrach

Hi, you need to have a reservoir rock, as well as a surrounding and overlying seal rock in order to form a trap.

However, the actual term 'trap' is referred to a peculiar structural and/or stratal geometric configuration which stops a further upward migration of the hydrocarbons, and 'traps' them within the reservoir rock. It is crucial to have a 3- or 4-way geometric 'closure' of the top reservoir horizon in order to obtain that.

Traps can be dominantly 'stratigraphic' (e.g. pinchouts, onlaps, stratal juxtapositions) or 'structural' (e.g., anticlines, tilted fault blocks, horsts, salt diapirs).

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.

Hi,

You can find helpful information these books.

First; oİL and Gas Production from Carbonate Rocks (Chilingar et al., )

and Marine Petroleum Source Rocks (Brooks and Fleet, 1987)

Greetings

Hi,

petrophysical measurements are a practical way to provide values of connectivity of pore space. Mercury injection in core samples gives estimation of porosity and permeability. The difficulty is to obtained undisturbed samples of the formation. Core sampling during drilling process remains is a solution but remains expensive.

The tortuosity can be defined as the ratio between the distance actually travelled by the fluid through the porous media divided by the macroscopic lenght (straight line from the inlet face to he outlet face). the pore connectvity index is used to describe the network potentially used by the fluid. The lattice gives informations for further permeability models. Some authors define the connectivity index as probabilistic measure which quantifies the likelihood of an established connection between two subspaces of porous medium.

The type of OM which is derived from aquatic environment is already consist mainly from Algae's ,Bacteria ,these particulate OM have bio polymer and mainly content Carbohydrates , Proteins ,Fats and other pigments and so on ..Already determines S1, S2, and S3, promising to generate oil mainly, other wise Higher plants which the mentioned above biopolymer lacking with it, but rich in Lignin (responsible for keeping the plants standing ,is promising to generate gas only .

Regards

Care must also be taken in using strontium ratios in marine carbonates. While they may reflect oceanic composition this is not always the case. Many marine organisms with carbonate skeletons (aragonite, calcite, or high mg-calcite) now appear to use biological preferences in their intake of Sr. This may also be influenced by local paleo environmental conditions; wind, turbidity, temperature, sunlight etc.

John Paul Jones

Thank you sir. I will read the articles you listed above as soon as possible. I have always doubted whether the "permeability jail" is distributed widely, cause some samples, their permeability is all <0.1md, are not characterized by the special zone, just as you said, "permeability" may not currently express the flow features for micro-,maybe nano-scale reservoir. I will also look related data and discuss with you.

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.

There's a body of literature out there about the Niger Delta, but it is not as extensive as the literature on other parts of the world, particularly onshore areas, probably because of the scarse data available to the academic community and very limited publications by operators working the offshore blocks in Nigeria.

From my time working the Niger Delta, understanding the structure of the region and the timing of that structure relative to maturation and migration seemed to be the hotbutton basin-scale issues.

Mining the references of a paper such as "A simple method of determining sand/shale ratios from seismic analysis of growth faults: An example from upper Oligocene to lower Miocene Niger Delta deposits" S. Pochat, S. Castelltort, J. Van Den Driessche, K. Besnard, C. Gumiaux (AAPG Bulletin, V. 88, No. 10 (October 2004), P. 1357-1367) might be a good place to start.

Alternately, I'd recommend checking the references on some of the broader, survey papers such as "Fifty Years of Exploration in the Niger Delta (West Africa)" Luc Saugy, Jerome A. Eyer, M. T. Halbouty, 2003, Giant oil and gas fields of the decade 1990-1999: AAPG Memoir 78, p. 211-226.

Plenty of proprietary basin analysis for the Niger Delta exists within the major operators, but that won't help you.

You should be able to do a lot with logs and seismic data. I'm assuming you have a basic log suite including gamma ray, resistivity, spontaneous potential, neutron, and density logs. From logs alone, you can do quite a bit of log analysis and petrophysics including net to gross calculations using gamma ray and/or resistivity cutoffs, relative reservoir quality delineation using resistivity and density, water saturation, and getting an approximate sense of fluid type with the neutron-density logs. All that said, the log response of tight gas sands can vary considerably. Some tight gas sands I am familiar with here in Colrado have no appreciable gamma ray or resistivity signature: density is the only good delimiter of the reservoir.

Regarding the calculation of gross in-place hydrocarbon estimates, you can use an equation involving porosity, water saturation, areal extent, stratigraphic thickness, irreducible water saturation, and recovery factor (if necessary). If the reservoir needs stimulation to produce, an estimate of effective frac radius will suffice for the reservoir dimensional properties I previously mentioned.

It would also be good to plug your estimated or calculated ranges for those reservoir parameters into Crystal Ball, @Risk, or some other probabilistic modeling package. It will help you understand the sensitivities of your parameters and the range of your uncertainties (e.g., the P10:P90 ratio).

Seismic data will allow you to make a structural model of the reservoir, understand faulting and general structure that can affect both migration over geologic time and faults as geologic hazards to drilling and completions. This assumes your gas sand is thick enough to be detectable with seismic. If not, the seismic is still useful for fault mapping.

Best of luck.