Reservoir Mapping While Drilling Tool Discovers New Hydrocarbon Pay Sand

Here is a short article sharing my experience using the Reservoir Mapping While Drilling (RMWD) Service named Geosphere (Schlumberger trademark) for drilling an infill well in an old field which has been producing oil for more than 40 years.

The RMWD tool consisting of a Deep Directional Electromagnetic Propagation tool was used together with standard Logging While Drilling (LWD) tools (Gamma Ray, Resistivity, Bulk Density and Neutron Porosity). The target reservoirs were deep-water turbidite sands. After the first sand lobe was successfully penetrated, the second lobe seemed to be shaled out. Under normal circumstances, the bottom section would have been plugged and abandoned and the well completed in the first sand. However, the RMWD tool managed to detect and map a hydrocarbon bearing sand 10 meters below the drilled hole. The drilling assembly was then pulled back and sidetracked into this newly found sand. Without the use of the RMWD tool, this bonus sand would have been totally missed.

Additional 315 meters of oil interval (along hole) was found in the bonus hydrocarbon sand, equivalent to additional STOIIP of 6.5 MMSTB. Additional GIIP of 2.8 BCF was also found.

For more details, please refer to SPE-182184-MS “Discovering New Hydrocarbon Pay Sand Beyond The Wellbore With Reservoir Mapping While Drilling Tool – A Case Study From Offshore Sabah, Malaysia”.

For the details on the planning and actual operations in drilling of this well, please refer to the following SPE paper. SPE-176120-MS “Success Story: A Development Concept Utilizing New Advanced Technology in a Very Old Complex Mature Field” APOGCE2015, Bali, Indonesia.

One thing to note is that, this Reservoir Mapping While Drilling Tool is NOT a “look ahead” tool. It detects bed boundaries and maps reservoir bodies up to 30 meters LATERALLY away from the well.

Sand Silt Clay Model Validation

An example of petrophysical evaluation (Sand Silt Clay model) results validated (corroborated) with core analysis data. This slide has been taken from an article by an ex-colleague of mine, who worked on this well.
This well is a newly drilled in-fill well in an old field which has been producing for a very long time.
The computed porosity and permeability values match very well with core analysis data. The computed water saturation values also match well with the Dean Stark analysis results.
The core plugs were drilled at wellsite and properly preserved and transported quickly to the laboratory in order to minimize drying and contamination. Special care was also taken to minimize mud invasion. Tracer analysis showed that mud invasion was 1% to less than 3%.
Comparison of the log-derived water saturation Swt (solid red color curve) with the water saturation derived from a Saturation Height Function (dashed green colour curve) for the field, indicates that the bottom-most interval in the oil bearing sand has been depleted. However, there is substantial amount of oil still left in the middle interval, where two formation fluid samples were taken. Formation pressure data were also obtained to determine the present day fluid contacts.

Sand Silt Clay Petrophysical Model

I have not posted anything on this blog site for quite some time, partly due to my traveling in the beginning of the year and mainly my laziness during the lockdown because of the current Covid-19 pandemic.

Here is a paper “Sand Silt Clay Petrophysical Model for Evaluating Shaly Sand Reservoirs in the Malay Basin”, which was presented at the 2008 SPWLA Asia Pacific Regional Technical Conference in Bangkok, Thailand. This petrophysical model was developed to better describe the lithological composition of the shaly silty sand reservoirs encountered in the Malay Basin, offshore Malaysia. However, it has also been successfully used in evaluating shaly sand reservoirs from other parts of the world. The Shaly Silt Sand evaluation model is not something new. In the SARABAND, shaly sand evaluation software developed by Schlumberger, there was a component called “Silt Index”. In the 1980 SPE paper “Log Interpretation in the Malay Basin”, Kuttan et al mentioned about the presence of very fine grained silt-size particles in the shaly sand reservoirs of Malay Basin. They developed a sand-silt-clay-water model which was used to determine the porosity and volumes of the matrix components of the rocks. 

There have been other triple-lithology petrophysical software, like the SSS (Silty Shaly Sand) model from Crocker Data Processing Pty. Hugh Crocker, the owner of CDP was one of the co-authors of the original SPE paper quoted above.

The present Sand Silt Clay model developed by PETRONAS Carigali is based on Kuttan’s paper, with many enhancements and additional features such as light hydrocarbon correction, bad hole correction, mixing data interpolation, infinite zonation, permeability estimation etc. Since the development of the SSC Model by PETRONAS, many updates and enhancements, such as permeability estimation, Saturation Height Function have been added. Here are the two papers presented on the Sand Silt Clay model, one in 2008 at SPWLA Asia Pacific Regional Conference in Bangkok, Thailand and another recent one in 2019 at AAPG Asia Pacific Conference in Kuala Lumpur, Malaysia.

Fresh Formation Water in Tight Reservoir Rocks Creates Contention Between Petrophysicsand Geoscience

Introduction

Evaluation of tight reservoir rocks, having low porosity and low permeability, is difficult enough. It becomes even more challenging when the formation water in these reservoirs is either fresh or has low salinity. The combination of fresh formation water and tight nature of the reservoir rocks causes the resistivity logs to read high, resulting in a low contrast in resistivity between fresh water bearing formation and hydrocarbon bearing one. This creates an uncertainty on the type of reservoir fluid and computed water saturation, if the formation water salinity is not known. Consequently, this becomes a source of contention between geoscientists who estimate hydrocarbon resource volumes and petrophysicists who provide the input parameters used in hydrocarbon resource assessment. This has been an age old problem, which still exists today. Although certain logs, such as the Dielectric log and Nuclear Magnetic Resonance log, may help in resolving this issue, oftentimes they are not available. Even the simple but useful Spontaneous Potential log, which helps to identify fresh formation water, is not available nowadays in wells drilled with Oil Base Mud or in those where log data is acquired while drilling with LWD tools. Formation Tester tools can identify fluid type and acquire samples, but the tight nature of the reservoir rocks poses additional challenges in getting reliable fluid gradients and samples. Several case histories are presented in this paper, highlighting the difficulties encountered in evaluating fresh water bearing tight formations. In all these wells, initial quick look evaluations indicate that the wells are probably fresh water bearing. However, being exploration wells, there were some opinions that they could be hydrocarbon bearing because of the presence of hydrocarbon shows on mud logs. Several attempts to take formation fluid samples using wireline formation tester either failed or were inconclusive. In some wells, Drill Stem Tests were carried out to acquire fluid samples and determine well deliverability if any. Most of these tests resulted in a very small influx of formation water into the well bore with little or no flow at the surface. Consequently, there was a contention about the validity of the well tests and the conclusion on the fluid type. However, bottom-hole samples taken during the tests indicate that the produced fluid from tested reservoirs was fresh formation water. When the salinity of the recovered water sample is used to re-evaluate the reservoirs of interest, they turned out to be essentially water bearing with some amount of residual hydrocarbon. Static Gradient Surveys carried out in these wells also confirmed some influx of fresh formation water. However, being a static survey, the SGS could not definitively resolve the issue of the formation fluid type. A spinner survey would not have worked at such a very small influx from the formation. Based in the available data, petrophysicists have interpreted the tested reservoirs to be water bearing, possibly with some amount of dissolved or residual gas. However, geoscientists would prefer to interpret them as hydrocarbon bearing and book recoverable resources. This now becomes a challenge to perform a conclusive petrophysical evaluation which is technically acceptable to all parties concerned

Case History 1 – Exploration Well: AX-1

An exploration well AX-1 was drilled in a producing field, offshore Malaysia, to explore and assess the hydrocarbon potential of the deeper reservoirs. As this well was an HPHT (High Pressure High Temperature) well, there was a limitation on the well logging tools that can be run in this well. The formation temperature in the target reservoirs was expected to exceed the temperature limit of most logging tools. Consequently, sophisticated tools could not be used and only basic standard logs were run in this well. The well encountered several sand packages in the deeper intervals. The sands were relatively clean with high resistivity readings around 20 to 30 ohm-m. However the average formation porosities were low, ranging from 5 to 10 p.u. In one particular reservoir sand, the total gas reading was around 8%. Several rotary sidewall samples taken in this reservoir sand indicated fine grained sand with poor visible porosity with no oil shows. Out of the three attempts made to take pressures in this particular sand, only one pressure test was classified as being valid. The pressure obtained was very high, confirming the over-pressured nature of the reservoir. Unfortunately, further attempts to acquire pressure data in the lower sands resulted in tight tests or seal failures. The decision was made to carry out a Drill Stem Test in this particular reservoir which seems to have the best reservoir properties compared to the lower sands. The DST resulted in a very low gas flow at the surface. As the rate could not be measured, it was estimated to be around 30,000scf/d using an empirical equation. Static Gradient Surveys were conducted after shutting in the well for several days. The SGS surveys indicated that the bottom hole reservoir pressure never managed to reach the initial pressure measured by the Wireline Formation Tester tool, implying that the sand is very tight. The SGS surveys also indicated that there is a small influx of formation fluids from the perforated interval. It is believed that initially a pocket of gas flowed into the well and the well could not sustain the flow. Bottom-hole samples taken during the SGS surveys recovered water, believed to be formation water. Measurements carried out at surface indicated the salinity of the recovered water samples to be around 3,000ppm Chlorides (equivalent salinity of 4,900ppmNaCl). Water saturation computed using this salinity resulted in high water saturation values, with an average gas saturation of about 25%. The well test also confirmed that there was minimal flow of gas at the surface, which could not be sustained or measured. The well also did not flow when it was opened up after the first build-up period, indicating that it was essentially dead.

Conclusions

Interpretation of well logs, well test and other available data indicate that the well AX-1 has a very small amount of trapped or residual gas. The tested reservoir is over-pressured and very tight that the well was not able to sustain any continuous flow. Bottom-hole samples acquired during the SGS surveys indicate that the salinity of the formation water is very low. There was a very small influx of fluids, most likely formation water into the well. Using the very low salinity of the recovered formation water, resulted in high water saturation with very small of gas in the formation. The sands below the tested reservoir are even tighter and most likely to bear fresh formation water also. It was agreed by all parties concerned, namely geoscientists, petrophysicist and reservoir engineers that these reservoirs may contain very small amount of gas but they predominantly contain fresh formation water. Similar case histories, presented in this paper, highlight the difficulties encountered in evaluating fresh formation water bearing tight reservoir rocks in the Malay Basin.

Water Saturation from Generic Capillary Pressure Curves

Here is the paper that my colleague Asari Ramli and I presented at The 17th Formation Evaluation Symposium of Japan in September 2011. There are many technical papers on Saturation Height Function (SHF), which is usually derived from capillary pressure data measured on cores. The SHF is commonly used in geological models to populate the individual cells of the model with water saturation values, as a function of some other petrophysical parameters, such as porosity phi, permeability (k) and height H (Height Above the Free Water Level).

This paper is the result of our work carried out based on the following assumption:

Sandstone reservoirs with similar Rock Quality Index RQI (loosely expressed as the Square Root of K/phi) and wettability will exhibit similar capillary pressure behavior with respect to the wetting phase saturation, namely water saturation. Therefore, the Saturation Height Function derived from the core plugs taken from the Malay Basin, offshore Malaysia, can be used to predict water saturation in similar sandstone reservoirs in other fields, regions or areas.

I hope this paper will be of interest to some of my fellow professionals. I do realise that some may not agree with it.

Are The LWD Resistivity Logs Telling The Whole Story?

Here is a paper on LWD (Logging While Drilling) resistivity logs, presented at the “20th Formation Evaluation Symposium of Japan” (Japan Formation Evaluation Society, SPWLA Japan Chapter) in October 2014. LWD logs have become common nowadays and replaced wireline conveyed logs in many areas, especially in drilling of appraisal, development and in-fill wells. Even in exploration wells, LWD logs are being run as insurance logging to secure well log data before any well problems are encountered. LWD logs have also come a long way since the days of the simple Short Normal resistivity log on MWD (Measurement While Drilling) systems. Data transmission rates have significantly increased and improved to acquire huge amounts of data in real time. Except for a few new generation logs, almost all types of well logs can now be acquired using LWD systems. The quality of LWD logs has also become as good as and even better than wireline logs in some cases. In this paper, case histories are presented on the seeminlgy anomalous responses of the standard LWD resistivity log, namely the Electromagnetic Wave Propagation Resistivity (EWR) logs. It is important to understand the principle and theory behind EWR logs so that proper decision can be made on the accuracy and validity of these resistivity logs.

Fluid Identification in Overpressured Low Porosity Shaly Sand Reservoirs

I have not been active lately, for several reasons: travelling quite a bit, busy with my volunteer work and having a sort of writer’s block, in other words, laziness. I started writing a short article on Shale or Clay Volume determination and have been stuck on finishing it. One of the reasons is the lack of a petrophysical software, which would allow me to draw crossplots without having to resort to Powerpoint, which is cumbersome. As this article is not yet ready, I am attaching a paper presented at the SPWLA Asia Pacific Regional Conference in Bangkok, Thailand in August 2008. It is not something out of the ordinary, but a real problem which faces petrophysicists who have to provide real time interpretations for operational decision making. The three wells mentioned in the paper were drilled in the same area, by the same operator. Fluid identification based on well logs alone was difficult, due to the low porosity and overpressured nature of the shaly sand reservoirs. The formation fluid which is at so-called “near critical” state makes it even more difficult. It is an old paper but hopefully is still relevant.

Gas Correction for Bulk Density and Neutron Porosity Logs

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.

Interpreting Neutron and Density Logs

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.