September 2011

OBJECTIVE

Related to our commitment to feed Geophysics UI Students and UISC AAPG members’ needs, this event has some objectives to reach to, and those are:

      To learn the basic concept of interpretation of seismic well log data

       To correlate seismic with well log data

      To practice in doing interpretation to determine the area that indicates possible accumulation of hydrocarbon at the subsurface

The University of Indonesia Student Chapter of AAPG has conducted a short course and workshop titled Well Log and Seismic Data Interpretation with M. Wahdanadi Haidar as the instructor. On this course, we are taught about the basic interpretation in well log and seismic data. Interpretation is the last part of proposing whether a reservoir is productive or not. After acquisition which is obtaining data on the field and processing the data where we try to get rid of noise and other things that can influence the readings of the well log and seismic data. Then the next step is to interpret and make a modeling of our reservoir based on its physical, chemical, and other properties.

Before getting into the interpretation part, we are first being reminded again of how we obtain these two data’s, well log and seismic data. First is the well log data, this data is obtained by moving the logging tool from the bottom part of the hole until it reaches up. While this movement is happening at a certain logging speed, the data are recorded at certain intervals called the sampling rate. And we end up by getting a group of “wiggly” lines for our data called a log. The basic purpose of getting these well log data’s is to know the lithology, resistivity, porosity, and the type of hydrocarbon that is contained in the reservoir. We get all of these information’s based on the information retrieved from the logging data.

 

WELL LOG

There are six types of basic well logs, they are the spontaneous potential log, gamma ray log, resistivity, neutron, density, and sonic. Each of these logs identifies different characteristics about the condition in the subsurface. From the spontaneous potential we can obtain the permeability and porosity of the lithology. Then we have the gamma ray log where we can know the lithology of our hole. The resistivity log itself can predict the reservoir characteristics. Then we have the neutron, density, and sonic logging tools, where from these three logs we can calculate and predict the porosity and fluid content around the hole logging

After knowing the types of logging tools, we are then taught of how each of these logging works. Starting from the spontaneous potential where it results from electric currents flowing in the drilling mud. What we can analyze from this log is first from its deflection. The deflection here is interpret as the permeable zone and the resistivity of the fluid content can be predicted from the direction of deflection and SP value. Not forgetting the resistivity of the mud filtrate must be known to prevent pitfalls in fluid contains resistivity in formation.

The gamma ray log tool is to record the radioactive material inside the rock formation that are usually deposited in shale (no permeability), Uranium, Thorium, and Potassium. From this log, we can identify the lithology, depositional environments, investigate the shale types. Not only that, we can correct from the GR log of clay content evaluation, identify organic material and source rock, fracture identification, geochemical logging, and study of a rocks diagenetic history.

Continuing to the next log which is the resistivity log, works based on 2 principal theories. The laterolog which sends ac current to formation, and induction log which inducts electrical current to formation. The induction tool is usually known as conductivity tools because its measuring conductivity and then we convert it to resistivity.

Last but not least are the three other logs used to calculate and predict porosity and the fluid content of the rock formations. The sonic logging tool is to measure slowness of compressional wave by the source giving out signal to the formation and will be received by near and far receiver. The two receivers will then calculate time between first break on near receiver and far receiver. This measured time will be changed into slowness by dividing with distance between near and far receiver.

Next is the litho – density tools that use a chemical gamma ray source and two or three gamma ray detectors. The gamma ray is shot to the rock and result Compton scattering, photon will be losing its energy and will be scattered to different directions. The energy that has been losed by the photon will be absorbed by electrons, making it free from its previous state. This process will cuycle until photon energy becomes weak and will be totally absorbed. Now the lDT measures electron density that scattered as result of gamma ray shot.

Then we have the compensated neutron tools (CNT) that can be used for predicting porosity of the reservoir. CNT spreads neutron to the formation, fast neutron will be slower when it hits hydrogen atom (elastic collision). This happens because size of neutron and hydrogen are similar. The detector in CNT will measure population of neutron in thermal region.

After the reading from the well log information, we then do formation evaluation based on the Archie equation and then continued with correlating between logs based on the readings that we have done.

The main base of doing seismic interpretation is to make asubsurface imaging by combining geological and peophysical data. The basic seismic interpretation uses PSTM seismic data flowchart.

Before doing interpretation, of course we have to prepare other back up data’s to support our study in and around the reservoir. Some of the data’s are regional geology repot, well log data’s, time depth survey from well (same with checkshot), seismic processing parameter, and data seismic loading. And there is also other kinds of seismic data, seismic data usually acquisition in 2D or 3D with several types such as raw seismic data, brute stack (from field processing), gather PSTM (can be used for AVO), final PSTM (pre stack time migration), last but not least is final PSDM (pre stack depth migration).

After receiving seismic and well log data, we then tie these two information together called the well tie seismic to create a correlation and mapping based on TVD (true vertical depth) not by TWT (two way time) mapping. As said before, after picking the horizon and tied up to the well log, we then make a horizon time/depth structure map. By multiplying the time domain with the velocity run through, we can get the depth domain map that we will use to locate the depth of our reservoir, because of course we measure the depth with depth domain not by the time domain which is what the seismic data is in. not to forget making the modeling of our reservoir, we can use seismic attributes to identify the data’s. but in this course and workshop, we did not reach this part because we have limited time to continue our study.

But we still got the chance in trying to pick horizons and correlating them with one well log position with another. We learn this manually without the use of software or computerization as from here we can try in doing it by hand first and later on when we study again on seismic interpretation. We don’t get controlled by the capability of the software, but we as future geophysicists control the work of our software and know the objectives of our every step to get a great result of interpreting and modeling of subsurface which are used in companies.

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