I would like to inform all that I am out of town (Toronto) and do not have my laptop with my notes and examples. I have written this post using my daughter’s laptop and made up the attached presentation on “An Exercise On Gas Correction For Bulk Density And Neutron Porosity Logs”. Hopefully, it is free from mistakes.

Gas or light hydrocarbon has an effect on well logs, in such a way that it reduces the bulk density and the neutron porosity values. This creates the undesirable effects of increasing the porosity derived from the bulk density log and at the same time reducing the neutron porosity. If proper correction for this gas effect is not performed, the computed porosity can be wrong. In addition to this, if gas correction is not properly done, the shale volume estimated from the combination of bulk density and neutron porosity logs can also be wrong. All of these can lead to miscalculation of water saturation values for the reservoir of interest. In this presentation, I have tried to illustrate how gas correction can be performed either graphically using the neutron-density crossplot or by simple averaging methods. I hope this will be useful to the young professionals.

Please note that my posts are usually about “Basic” petrophysics. They are meant for the young professionals who are embarking on their careers in petrophysics or for those who are interested in the basic principles and theories of petrophysics. They are not about advanced theories and principles. The neutron porosity and bulk density logs are used to identify reservoir fluid type in addition to computing the formation porosity. In order to correctly identify the reservoir fluid type, the neutron porosity log and bulk density log must be plotted and displayed on what is known as compatible scales.

As an industry standard the Neutron Porosity log is recorded in Limestone Porosity Units and displayed in either V/V units, P.U. (Porosity Units), % (percentage) or decimal units (dec.).

The Bulk Density is displayed in gm/cc (oilfield units) or kg/m3 (kg/cubic meter) in SI units. The neutron porosity logging tool is calibrated in limestone porosity units and the bulk density logging tool is calibrated in density units.

The following article explains about how the neutron and density logs should be plotted and displayed on compatible scales to facilitate in identification of reservoir fluid type.

The lithology in the interval of interest is: CARBONACEOUS SHALE

It is not COAL as mentioned by some respondents.

Although the neutron and density log responses are somewhat similar to those of coal, there are significant differences in the responses of the other logs, such as Gamma Ray (GR) and resistivity logs.

The GR log in this interval is not as low as in the coal layers. In fact, the GR log response indicates that the interval is relatively shaly.

The resistivity readings are also not very high as in the coal layers.

There are two coal layers in the log section and responses in these coals are different from those in the interval of interest.

Coals usually have the following features on well logs:

• Very low Gamma Ray values
• Very high resistivity values
• Very low bulk density values
• Very high neutron porosity values

As an introduction to my next post on interpretation of Neutron Porosity and Bulk Density logs, here is a quizz on lithology interpretation. What is the lithology in the interval indicated by the blue arrow on the neutron porosity and bulk density logs? Again, this is just to stir up some interest on the basic interpretation of neutron porosity and bulk density logs. It is not meant to insult the intelligence of anyone. The answer will be given in my next post. Have fun!

Resistivity logs can be severely affected by borehole conditions and the fluid (usually mud) inside the wellbore, where the resistivity logging tools are deployed. From the old generation ES (Electrical Survey) tools up to the latest generation Array Resistivity tools, there are many factors which influence the measurements recorded by the logging tools. In certain cases, the readings become so anomalous that doubts are being cast on the validity of the log readings and functionality of the logging tools. These anomalies may be the results of the borehole conditions and fluid effects and nothing is actually wrong with the logging tools. The attached article illustrates the deleterious effects that borehole environment and drilling mud can have on the resistivity logs.

The possible causes to the anomalous resistivity log readings were given by the service providers. Please note that the purpose of this article is not to put blame on any one particular company. As usual, my sole aim is to share knowledge.

The answer to the previous quizz on LWD resistivity log is given in Figure-4.

My apologies for not being able to answer individually to all those who commented or gave answers to the resistivity quizz.  

The fluid type in the interval of interest is: AIR Although the neutron porosity and bulk density logs have a crossover response similar to that of gas (hydrocarbon gas), there is NO gas in this interval. The mud log has NO gas shows. The well was drilled on a mountain as indicated by the Derrick Floor Elevation of 3,715 feet above Mean Sea Level. This further supports that the fluid in the zone (1,300 to 1,600 feet abover MSL) is AIR. Several people got the fluid type correct. There were some interesting answers and comments also. The formation cannot be salt. The sonic is reading too high, around 100 to 120 us/ft. Salt should have a very low DT (67 us/ft). It cannot be coal also. Coal has very low bulk density, very high neutron porosity and low Gamma Ray. The well was drilled by a partner company and their “End of Well” report stated that the fluid type in the zone of interest is AIR.

Several years ago, I was asked to look at a log plot and determine the fuid type in the formation. It is an interesting piece of log, although the quality of the plot is rather poor. It is a composite plot of well logs and mudlog. The question is what is the fluid type encountered in this interval of the formation. A hint is given at the bottom of the log plot. I will give the answer in my next post. I am posting this quizz for fun and do not mean to insult anyone’s intelligence.

The use of powerful computers and sophisticated software nowadays has made petrophysical evaluations look easy, something which can be quickly performed at a push of a button. Without knowing the basic theories and principles behind petrophysics, blindly relying on software to produce these evaluations can lead to misinterpretation which can have serious consequences such as missed opportunities or wrong economic assessment, either over or under estimation, of the field potential. There are times also, where digital data is not available and manual interpretation of the petrophysical data has to be carried out by hand. At such a time, it becomes very important to know the basics and “the rule of thumb” methods to carry out a meaningful interpretation. There are also times, where conventional interpretation with standard methods cannot provide a satisfactory evaluation and some “tricks of the trade” need to be used to provide the best possible solution to the problem. In this presentation, some case histories are presented on the importance of knowing the “rules of thumb” and “tricks of the trade” to help petrophysicists in their work.

Accidental hydraulic fracturing of a formation during drilling operations can happen when the Equivalent Circulating Density (directly related to mud weight) of the drilling mud exceeds the rock strength of a particular formation. Under normal circumstances, the mud weight will be kept at a certain optimum value during drilling. However, there are times when it needs to be increased due to various reasons such as borehole stability issues, high pore pressure, fluid influx, etc.

Sometimes, while increasing the mud weight to counter these issues, a certain formation higher up in the open hole can be fractured. When a formation is fractured during drilling, some amount of borehole fluid (drilling mud) is injected into the formation. This results in loss of drilling fluid into the fractured zones. The severity of the lost circulation will vary from case to case. The location of the hydraulically fractured zone can be identified on well logs if there are logs recorded in the well before and after the fracturing has taken place. Nowadays, LWD (Logging While Drilling) logs are run while the well is being drilled. These “before-fracture” logs (real time logs while drilling) are recorded in the formations before they are fractured by a higher mud weight. These LWD logs can again be recorded in a “ream-out” mode after the well has been drilled. These “after-fracture” logs can be used to identify the zones which have been hydraulically fractured by comparing with the “before-fracture” logs. In cases, where wireline logs are run after drilling the well, these can also be used as “after-fracture” logs to be compared with the LWD logs acquired during drilling operations. Usually, there will be significant differences in the resistivity log profiles between the “before-fracture” and “after-fracture” logs. In the following two wells (refer figure 1-6), accidental hydraulic fracturing by high mud weight occurred in both of them. The fractured zones can be identified by comparison of “before-fracture” and “after-fracture” resistivity logs. Both wells were drilled with SBM (Synthetic Base Mud) which was lost into the fractured formations during the event of hydraulic fracturing. Due to the injection of the non-conductive SBM into the fractured zones, significant changes on the resistivity logs can be seen.

In both wells, there were LWD resistivity logs while drilling, while reaming out after drilling and wireline logs after reaching the final depth of the well. The fractured formations were very shaly and the resistivity is low on the “before-fracture” logs. Due to the injection of the resistive SBM mud into the fractures, the resistivity has increased significantly on the “after-fracture” logs. In both these wells, the formations high above in the wells were accidentally fractured by increasing mud weight. There was lost circulation in both wells due to mud being lost into the fractured intervals. However, the effects on the LWD resistivity log, namely the increase in resistivity due to SBM entering the fractured zones, were not noticed. This was due to the fact that the “Trip Out” LWD logs were not available at the well site. When the wireline logs were run afterwards, there was significant increase in resistivity over these fractured zones. These high resistivity zones created a lot of excitement in the exploration teams. Subsequently, several pressure measurements (possibly samples if pressure tests were successful) were attempted in these zones. All of the attempts failed and resulted in tight tests.

Lesson learnt: In case where accidental hydraulic fracturing is suspected, record LWD resistivity logs while tripping or reaming out of the well. Get these “trip-out” logs processed and produced at the well site by the LWD service providers. If there are significant changes in the resistivity values between the “Real Time” logs and “Trip-Out” logs, the occurrence of accidental fracturing can be confirmed. In such a case, do not attempt to take formation pressures and samples in these fractured zones. Most likely, these attempts will fail and result in tight tests, with inherent loss of time and money spent on the dry tests.

I apologize for the poor quality of the log examples as they were copied and pasted from my PDF file. I could not locate the original Word document.

Note: In “Example Well 1”, PEX (Platform Express) is a trademark of Schlumberger

For a change, instead of posting presentation files, I will post some short articles that I have written over the years. Hopefully, these will be of interest to the petrophysics community at large. Way back in 1996, I presented a paper titled “Efforts Toward Improving Formation Evaluation“, at the Petroleum Geology Conference 96, organized by the Geological Society of Malaysia. In that presentation, I mentioned several challenges faced in evaluating the hydrocarbon bearing reservoirs in Malaysia. One of these challenges is the so-called “Low Resistivity Low Contrast Pay Sands” or LRLC Pay Sands. The challenges in evaluating LRLC pay sands still exist today, not only in Malaysia but also in other places in the world. Here is a short article that I wrote on this subject. I apologize for the poor quality of the log plots, as I had to copy and paste them from a PDF file. I could not locate my original Microsoft Word document for this article.

Low Resistivity Low Contrast (LRLC) pay zones are hydrocarbon bearing reservoirs with low resistivity or low contrast in resistivity log responses due to the influence of a variety of factors associated with mineralogy, water salinity, and microporosity, as well as bed thickness, dip, and anisotropy. Low-resistivity pay is generally characterized by pay zones that cause deep resistivity log curves to read low, usually around 0.5 to 5 ohm-m. This is often attributed to a combination of shale content, mineralogy, microporosity and thin beds. Low-contrast pay implies a lack of resistivity contrast between pay sands and adjacent shales or wet zones. This problem is most commonly seen when the resistivity tool encounters a zone that contains fresh water (or waters of low salinity). As salinity decreases, the electrical pathway through a body of water becomes weaker and more dispersed, thus causing the water to become less conductive (or conversely, more resistive). Therefore, while the resistivity of the pay zone may not be low, the resistivity of the water leg is high enough to make it difficult to distinguish between pay and wet zones.

Causes of Low Resistivity or Low Contrast Pay Zones

A number of factors have been found to act on the logging tool to produce low resistivity or low contrast pays. In Moore (1993), Darling and Sneider cite the following causes:

Bed Thickness: some pay zones are simply too thin to be resolved by the logging tool.

Grain Size: very fine grain size can lead to high irreducible water saturation.

Mineralogy: conductive minerals (such as pyrite, glauconite, hematite, or graphite) or rock fragments can have a pronounced effect on resistivity response.

Structural Dip: dipping beds produce significant excursions on the resistivity log when orientation between the tool and the bed deviates from normal.

Clay Distribution: classified as either dispersed, structural, or laminated – all capable of holding bound water.

Water Salinity: high salinity interstitial water causes low resistivity within the pay zone, while low salinity water can cause low contrast pays.

Any combination of the above: often a combination of inter-related factors, causes the logging tool to read lower resistivity than normal inside a pay zone. Of all of the factors listed above, probably the most common cause of low resistivity pay is the simple combination of thin beds containing highly conductive shales (and their associated bound water), along with thin pay sands which are below the vertical resolution of the logging tool. (Source: IHRDC).

Fig 1: A core through a laminated interval. (Source: IHRDC)

Fig. 2 – Low resistivity gas sand. The main target sand is gas bearing although the highest resistivity in this sand is only 2.5 ohm-m. This field tested 25 MMCSFD gas in each well from this sand.

Fig. 3 – Low resistivity (3 ohm-m) oil sand. DST results: 2600 BOPD on 96/64” choke. No water production. Average Sw = 70% computed from conventional logs. Nuclear Magnetic Resonance Log indicates movable hydrocarbon.

Fig.5 – Very low resistivity gas sand. Resistivity is less than 1 ohm-m. Tested 3.6 MMSCFD of gas from the perforated interval (1354–1397) mMDDF interval.