Low resistivity low contrast (LRLC) pays/intervals mostly are being examined via behind casing analysis and produced thru production enhancement works from idle wells in numerous oil fields in Malaysian Basin. However, with the aim of unlocking hydrocarbon volumetric LRLC potential, it should include seismic data analysis in addition to formation analysis behind casing. In the past, these LRLC intervals were often ignored and considered as water-wet sands due to high water saturation or as tight sands. These intervals, which contain significant reserves, have been recognized and presented in several technical papers explaining its appropriate identification and evaluation techniques using well-data (logs and samples/cores). The economic importance of LRLC pay sands in the Malaysian Basin has just recently been demonstrated. These pays may lead to a large areal extent and may contain ten to hundred millions barrels of hydrocarbons. The integration and proper techniques of petrophysics and geophysics may become a vital approach for understanding the hydrocarbon distribution (volumetric) within a large areal extent. The possible environment of depositional for developing LRLC reservoirs are: 1) deep water fans including MTD (mass transport deposit), 2) turbidites, 3) shoreface (middle to lower part), 4) delta complex (i.e. delta front and toe deposits), and 5) channel fills. The LRLC may not occurred in alluvial fans and aeolian deposits. These 5 environment of depositions may accumulate several types of LRLC sediments such as: laminated intervals; bioturbated intervals (with dispersed and/or structural clays); altered framework grains and/or smaller grain size (i.e. silty sand reservoir). The thinly laminated sand is probably the most significant reservoir in term of producing hydrocarbon comparing to the other LRLC types. The understanding of logging tools (wireline, LWD) and its responses can be used to build petrophysical and rock-physic models that can evaluate these LRLC reservoirs. But having available advanced logs such as NMR, Image, sonic (Vp and Vs) logs, it is a plus for a better analysis. Furthermore, an elastic property (rock physics) from seismic data may establish a clear separation for different lithology and fluid saturation on LRLC sands and may lead to future recommendation work on LRLC reservoir characterization. The objective of this paper is to provide the above understanding with explanation and examples. Introduction In Malaysia basins, the LRLC (Low Resisitivity Low Contrast) sands are being recognized and brought into production recently. Previously, these sands were considered negligible in term of its commercial; but now, it has enough evidence confirming by available well-data that these sands are of economic importance. With occurrences of numerous productive intervals have been indentified, it encourages us on understanding further on its geologic background, depositional scheme, geophysic assessment, and proper formation evaluation from available well-data such as well-logs, cores, and production history.

Thinly bedded reservoir study in the deep-water area, offshore Sabah, Malaysia, was performed with the primary objective of improving the understanding of its complex geology. The nature of reservoirs, which are predominantly thin-bed and laminated sandstones of submarine fan environment, contain a high level of uncertainty in its lateral continuity. Standard shaly-sand log analysis methods contribute pessimistic values of porosity and water saturation when applied to these reservoirs. Few techniques are then presented for the determination of these rock properties, which are more reliable with core and production data. Core grain-size analysis of these reservoirs shows that clay content is generally low but the silt content can be significant. Furthermore, log responses show that porosity distribution and mineral-conductivity are influenced mainly by the silt-size particles. A sand-silt-clay (SSC) model was then developed from density-neutron crossplot, which model is also used to determine porosity and water-saturation in addition to volumes of lithology components of the reservoirs. Furthermore, other petrophysical technique, called SHARP, uses 1D convolution filters to match thin bed modelled log curves to their corresponding measured responses. A petrophysical evaluation using standard resolution logs and the thin bed resistivity (SRES) from image response are used to develop a thin bed model that yields high resolution logs. For zones where the resistivity image indicates significant thin bed development, the standard petrophysical analysis should also indicate the existence of free fluid. Although the porosity tools cannot resolve the thin beds, they nevertheless represent the bulk volumetric over the interval, known as Thomas-Stieber-Juhasz (TSJ) method, and would be able to differentiate between porous zones with lower clay volume versus porous shales with high clay volumes. The main point is that if a thin bed interval has some calculated free fluid volume using standard resolution logs, then a thin bed analysis is warranted.

The sedimentation in deepwater environments commonly includes deposition of thinly-bedded pay zones that are difficult to be characterized using standard seismic and logging techniques. Furthermore, these zones are often left unexploited and even overlooked during drilling, as they are finer in resolution than it can be detectable in conventional open-hole logs. The paper presents an integrated multi-disciplinary study on thinly-bedded reservoir characterization in deep water areas in Malaysia. The adapted workflow consist of: (1) Seismic Data Conditioning, (2) Petrophysical SHARP Analysis, (3) Simultaneous and Rock Model Building, (4) Lithology Prediction, Hydrocarbon Volume, and Net pay, (5) Stochastic Seismic Inversion and Geo-statistical Modeling, and (6) Reservoir Simulation and Validation, (7) Uncertainty Analysis, (8) Sedimentological Analysis using Core-Image, and (9) Geomechanical Rock Property Analysis. Petrophysical diagnostics using high quality resistivity images of OBMIs, as log input for thinly-bedded modeling, was the primary driver to establish effective elastic properties through AI vs. VP/VS cross plot (for lithology prediction) and AI vs. total porosity cross plot (for porosity prediction) within the model. These cross-plot transforms are then upscaled and applied to build a cascading of deterministic inversion (simultaneous AVO inversion) and stochastic inversion of 1-ms sampling, which are calibrated to core and neural network litho-facies interpretation for lithology and porosity modeling. The geo-statistical modeling workflow was initially built-in with 7 exploration wells that have OBMIs (Oil Base Micro Imager) as the typical model. Numbers of reservoir properties realizations were generated by generating geo-cellular grid over the zone of interest. These realizations could provide an improved lithology, porosity and fluid determinations and could lead to estimate a more robust volumetric, particularly within such thinly-bedded reservoir. The developed unique integrated workflow was applied on the field under study showing about 30% increase in in-place volume and was successfully validated against available production/well data as well as new drilled wells.

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PETRONAS is interested in monetizing X Field, a high CO2 carbonate gas field located in East Malaysian waters. Because of its location (more than 200 km from shore) and the preferable geological formation of the field, reinjection of produced CO2 back into the field's aquifer has been considered as part of the field development plan. To ensure feasibility, the PETRONAS R&D team has conducted a set of laboratory analyses to observe the impact of CO2 on the carbonate formations, through combining the use of static CO2 batch reaction experiments with advanced helical digital core analysis techniques. The analysis of two representative samples, from the aquifer zone is presented here. The initial state of the samples was determined through the use of theoretically exact helical micro computed tomography (microCT) techniques. The images were processed digitally to determine the porosity and calibrated with RCA to ensure the reliability of digital core analysis results. After scanning, both plugs were saturated with synthetic brine with similar composition as the fields' formation brine and aged with supercritical CO2 at reservoir temperature and pressure for 45 days. After 45 days, the aged core plugs underwent post reaction analysis using micro-CT scan and image processing software. Based on macroscopic observation, the core plugs showed no changes after aging with supercritical CO2 at high pressure and high temperature (HPHT) as per reservoir condition. However, analysing the high resolution micro CT images, the team was able to determine the changes in porosity before and after CO2 aging, which are around 1%.

There are a number of additional challenges in the development of high CO2 content gas fields. To meet the requirements of the Kyoto Protocol and Paris Agreement, an efficient means to deal with the produced CO2 such as re-injection into the reservoir for sequestration is required. With the intention of developing such high CO2 gas fields, PETRONAS has identified a trial candidate (X field) offshore Sarawak Malaysia, which is a carbonate gas field with 70% CO2 content and good potential to re-inject the produced CO2 into the field's aquifer zone. To study the feasibility of CO2 reinjection, PETRONAS R&D team are studying the effects of re-injected CO2 on the mineralogical and petrophysical properties of the reservoir and decided to incorporate Digital Core Analysis (DCA) into the case study. Although porosity determination and other petrophysical property characterisation using micro-CT images has been widely used for a number of years, there is still discussion about its accuracy and reliability. Based on previous internal studies, porosity determination via digital core analysis can be limited by the quality and resolution of micro-CT images collected and thus the capability of the image analysis software. This case study investigates accuracy and reliability of the use of contrast enhanced imaging practices and the use of the helical micro CT for porosity determination via Digital Core Analysis (DCA). PETRONAS adopted and optimized a contrast enhanced imaging methodology for use on 1-inch core plugs during scanning via a helical micro-CT and applied this as a case study to X field with the help of a technology partner to evaluated digital core analysis. In the same year, a commercially available image analysis software was launched, with such a DCA workflow in mind. Using this optimized methodology and the newly launched imaging software, the porosity values from DCA of the 1-inch core plugs show good correlation to the values from Routine Core Analysis (RCA) done on the same samples, with less than 1.5 porosity unit difference. In this case study, PETRONAS managed to compare the porosity obtained from DCA directly with porosity measured by RCA. This methodology will be used for porosity determination for wells or other regions of interest where limited samples or different sample sizes are not suitable for RCA.

Bioturbated zones are frequently bypassed by oil and gas operating companies during perforation due to the perception that they are non-productive. We analysed data from wells in four fields in the Sarawak Basin, Malaysia, for selected bioturbated zones. The study included thin section, probe-permeameter, petrophysical, and routine core analysis. A bioturbation index classification scheme was established to allow semi-quantitative ranking for each foot of core. In the current study, we introduce a simulation script to predict lithofacies types at well locations based on input from bioturbation intensity algorithm (Ali et al., 2016), this script can be used for application on shallow marine field within Malaysia. We also used post stack seismic inversion for acoustic impedance and it proved to be a key approach to enhance the ability of predicting rock properties between wells. We generated a seismic derived lithofacies which provided the best estimate of lithofacies distribution between wells even though a well derived lithofacies had higher resolution. We calculated STOIIP using input from seismic lithofacies and porosity, and the results showed more accurate estimate of hydrocarbon in place compared with statistical approaches. Thus, the current seismic lithofacies methodology can be used for static model building and STOIIP calculation in shallow marine environments.

Nuclear magnetic resonance (NMR) T2 spin-spin relaxation is a well-established technique in petrophysics labs for quantifying bound/free water and pore-size distribution of reservoir rocks. The method has also been used to measure oil and water saturations, and to characterize wettability alterations for oil/water/rock systems. The T2 relaxation distribution measured by hydrogen NMR is the sum of contributions from both oil and water in the core. It is therefore necessary to separate the T2 signals of oil from water. Since deuterium oxide (D2O) does not have a NMR signal at the resonance frequency for hydrogen, brine made with D2O is commonly used as the aqueous phase to determine the oil saturation from NMR. The objective of this work was twofold: (1) to validate the oil saturations in the core with NMR T2 relaxation at connate water saturation (before and after aging) and residual oil saturation after waterflooding; and (2) to investigate the potential hydrogen-deuterium (H-D) ion exchange between rock minerals and D2O. Berea sandstone cores were used along with the crude oil from one of the fields in the Sarawak Basin, Malaysia. The aqueous phase was a synthetic brine made with either deionized water or D2O. Two cores containing the crude oil with D2O brine as the connate (or initial) water were aged at 75eC for up to 65 days. During the aging period, the cores were scanned three times for T2 measurements. The measured T2 volumes (supposedly a measure of the oil volume) of the two cores kept increasing as the aging time increased. However, mass balance indicated that the oil saturation was the same before and after aging. The inconsistent oil saturation measured by NMR indicated that there was H-D ion exchange between the rock minerals and D2O. The cores were then flooded with the fresh D2O brine, after which the residual oil from NMR agreed with that from mass balance, indicating that the fresh D2O had replaced the connate D2O brine affected by H-D ion exchange. Additionally, two cores fully saturated with D2O brine were also measured by NMR before and after aging at 75°C, again confirming the H-D ion exchange between the rock minerals and D2O. Finally, the mixture of the crude oil and D2O was measured by NMR before and after aging at 75°C, indicating that the interactions between the crude oil and D2O increased the T2 relaxation time. The total T2 volume was not affected. This work provides evidence of H-D ion exchange between rock minerals and D2O at elevated temperature. It is recommended that such interactions between the rock minerals and D2O brine be considered for related tests, especially when elevated temperature is involved.