Low Resistivity low contrast (LRLC) reservoirs were normally disregarded due to high water saturation and classified as tight sand. LRLC reservoir defined as Pay that has low resistivity contrast between sand and adjacent shale due to presence of conductive mineral or fresh water. Hence, this paper will transform the standpoint by demonstrating values and potential reserve addition underneath LRLC reservoir which proves that it could contribute equally as the conventional reservoir and realizing potential reserve growth. HY field located in Baram Delta Basin East Malaysia has been producing for more than 40 years and classified as lower coastal plain to coastal environment. The reservoir is loosely consolidated, fine to very fine sandstone and interbedded with shale. Z reservoir (Low Resistivity contrast reservoir) initially identified as gas-bearing reservoir with fresh water salinity of 2k-4kppm. Plus, difference in resistivity values between sand and adjacent shale only separated by ~3ohmm .Due to these claims, there is no Oil interpreted below the gas level and been neglected for years. A robust water salinity investigation supported with the geological point of view and water sample taken at the wellhead, Project Team proposed the water salinity should be 10k-15k ppm which is more saline than previously assumed. Revision in water salinity value has led to pinpoint Z reservoir as Oil bearing reservoir and recover estimated ~200 ft Pay of Oil column in Z reservoir. An appraisal well was drilled for data gathering and exploring potential in the deeper sections, hence serve as a platform for further petrophysical evaluation in the Z reservoir. As a result, Project team managed to take Oil sample and Oil gradient for Z reservoir. In addition, PVT lab result showed the oil sample taken having similar fluid property as the produced oil in the major reservoir. Based from the existing static model, potential additional of recoverable reserves was calculated around 20 MMstb for the Z reservoir. This has been an eye opener for the team to give an extra attention and emphasis on the true potential beneath the LRLC reservoir.

Well abandonment has been associated and considered since in the Field Development Plan stage. Worldwide, government and legislative authorities are having specific requirement and regulation in ensuring the oil and gas industry to seal and permanently take offline unproductive wells to prevent them from impacting the environment and safety. When all feasible opportunity is exhausted and no remaining economic potential is proven in a well or field, it will proceed to abandonment, saving money spent on well liability cost. In effort to reduce the P&A cost which has no financial return, operators and regulators strive to improve P&A method to increase efficiency without compromising safety. The production of oil and gas, whether or not enhanced by the injection of water or gas, will cause a change of pressure, stress and temperature in the reservoir and its surrounding formations. Additionally, chemical characteristics of the injectant, may reactive gases for storage or production enhancement, may lead to changes in petrophysical, geomechanical and chemical properties of subsurface formations, faults and wells equipment. These changes may or may not have a detrimental effect on the containment of toxic or otherwise harmful fluids and gasses in the subsurface. The comprehensive P&A analysis and program is vital to ensure the security of well containment. Loss of containment may lead to potential loss of life, assets, environment and reputation. This paper will discuss the analysis done by Petrophysicist in supporting the decision and design of well P&A design, either isolation at reservoir level or caprock level. After no remaining potential and shallow hydrocarbon is verified, the well will be conditioned for pressure analysis and caprock assessment, by formulating well dynamic strength parameters, namely Young modulus and UCS and establishing pressure column. The competent caprock at the proposed barrier depth will be assessed, benchmarked and inventoried for regional caprock understanding, taking account input from multidiscipline. In addition to additional assessment on rock strength in well P&A design, this paper also recommend the multidiscipline future collaboration assessment technique for better regional caprock understanding. When possible, this method is able to provide feasible P&A design with some confidence level at the competency of the withholding caprock.

Coring and core analysis are considered the only direct and physical data to provide a true reflect to the reservoir properties. The measured properties are used to calibrate subsurface models and ensures close to reality properties. Representative data is critical to allow achieving such target. Coring planning and close follow up from the day decision is taken to core is important to achieve representative data. The approach followed in this manuscript allowed a high probability of successful core cutting, and representative core analysis. Field A is planned for appraisal phase and reservoir is expected to be of low permeability with sequence of shaly sands which adds complications to achieve the objective in cutting and analyzing the core. Different coring technologies were evaluated against the main coring objective of potential hydraulic fracturing field development. Conventional core is selected to offer the best value in both cost, and data coverage in compare to sidewall core. However, due to financial impact only one run was allowed, consequently it was critical to get the highest possible recovery and highest quality in one shot. An extensive planning phase investigated all variables to ensure high recovery. Rock strength and its mechanical properties allowed the selection of optimum coring parameters, coring accessories, and coring bit. It is critical to the project to collect the core and the added challenge of only single run required detailed workflow. Borehole size, mud wt, rate of coring and coring parameters were challenging due to the given one time opportunity. As a result, successful 100% core recovery is achieved, core retrieval to surface ensuring least core damage, this is demonstrated by CT scan which indicated no tripping out induced fractures. Well site core preservation reduced any weathering alteration, the selected stabilization method allowed minimal invasive to the core. Electrofacies guided by the whole core CT scans allowed the best coverage to the reservoir's properties. Long and large diameter plugs were achieved. Cleaning pilot study facilitated the selection of least damaging cleaning and drying method. Pilot small core analysis programs, and close follow up, and the analysis of raw data reduced the risk of unrepresentative core analysis results. Conventional core analysis data allowed refining and enhancing premeasurement electro facies and allowed a distinctive rock typing. The detailed planning permitted us to secure 100% core recovery and ensured core is reached the surface with least possible damage. The followed core analysis strategy reduced redundant experiments and allowed representative results at the same time optimized on the cost. This paper demonstrates the best practice that is followed in challenging environment of shaly sand sequences to successfully cut core and develop a program, and workflow which reflects the uncertainties to be solved.

Characterization of conventional clastic reservoirs can be very challenging because of issues related to the nature of the reservoir, logging environment, and/or production enhancement projects being performed within the field. In the subject reservoir, the primary challenge was typifying hydrocarbon, in terms of gas or oil, in a well drilled using synthetic oil-based mud (SOBM) as well as in a relatively fresh formation water-bearing reservoir in which a waterflooding project was being performed. Furthermore, the shaly and silty nature of the reservoir and the uncertainty of the resistivity (Rw) value and other saturation equation parameters added to the complexity of this task. Another challenge was calculating residual oil saturation in one zone with the presence of SOBM filtrate containing a 20% water phase and incomplete information about the saturation exponent, n, in the imbibition process because of water injection in the field. To meet such a challenging reservoir situation, nuclear magnetic resonance (NMR), in multi-Te activation, and dielectric logs were acquired along with quadcombo, wireline formation tests (WFTs), and oil-based mud imaging (OBMI). As a normal practice, formation evaluation was performed using the NMR T2D technique and dielectric complex refractive index modeling (CRIM) along with quadcombo and WFT for (1) mineralogy and porosity calculations, (2) fluid typing and quantification, and (3) permeability estimation. A slight viscosity difference between the formation oil and SOBM filtrate was evident on the T2D map, and differentiating the various oils and quantifying residual oil was possible. Dielectric shallow resistivity, water filled porosity, and the estimated cementation exponent, m, all played major roles supporting the NMR T2D processing, particularly when restricted diffusion was experienced as well as to fill gaps across intervals where NMR was not acquired. This paper discusses the reservoir challenges experienced and the solution workflow, with emphasis on the pros and cons of the different techniques used and recommendations for future projects. Data used in this study were acquired from a well offshore Peninsular Malaysia.

Carbonates reservoir has an elevated level of heterogeneity than clastic reservoir, which is relatively controlled only by depositional facies. It is because of the facies variation vertically and laterally which is more intensive, as well as intensive diagenesis. Therefore, an accurate method is required to ensure hydrocarbon development is effective and efficient. Challenges in the characterization of the carbonate are related to rock type and porosity. The permeability of rocks cannot to determined only by porosity. The method that can be used to determine rock type and rock permeability estimation is through rock typing method. This method is aptly applied for carbonate reservoir which is dynamically change due to diagenesis. It is believed to predict and optimize carbonate reservoir better. Core data can be used to determine rock type based on geology named litho-facies or petrophysics named electro-facies characterization There are many rock typing methods, which are Pore throat group based on shape and trend, PGS - Pore geometry structure, Lucia, FZI – flow zone indicator, Winland R35. Those methods use different principles in classifying rock type. Main objective to merge core results between geological statement information based with digital engineering data. By combining these two pieces of information and data, the more precise rock type and able to achieve in solving more finer on carbonate reservoir characterization. Furthermore, the analysis has been conducted over multiple carbonates environments including platform carbonate, pinnacle carbonate and complex carbonate lithology. This paper presents the rock typing classification in carbonate environments which consider geological, and engineering elements mainly through Pore Throat based Rock typing. The main rock typing group can be derived from either stratigraphy or the distribution shape of the pore throat. This will produce the porosity-permeability relationship for all the samples. Geological inputs are then used to describe more refined and detailed characteristics of the relationship. These variety sets of data will help to populate the geological features of the reservoir in bulk and each individual layer in depths. The process includes developing the correlation between pore throat size and pore throat connectivity networking. Defined from core plug pore throat pattern and tie to well logs respond. Consequently, to be propagated in the non-cored intervals through correlation between multiple well logs respond. Some of the key petrophysical measurements will be discussed and how to interpret the borehole images associated with carbonates. As well as looking at different methods of rock typing and best practices to build a static carbonate model. This approach is using pore throat group to classify the rock typing of the carbonate reservoirs. The main rock typing group can be derived from either stratigraphy or the distribution shape of the pore throat. The methodology must be tested first in cored intervals. This is to ensure that sufficient data has been incorporated considering the complexity of the carbonate structure. This will produce the porosity-permeability relationship for all the samples. Geological inputs are then used to describe more refined and detailed characteristics of the relationship. Post drill analysis of the core plugs usually come from the sedimentology analysis, thin section, SEM, XRD and even the core photos. These variety sets of data will help to populate the geological features of the reservoir in bulk and each individual layer in depths. These will be the steps that will aid in re-clustering the porosity-permeability relationship. After these steps have been implemented, the outputs will be calibrated before the methodology will be adopted and regressed to the un-cored intervals. The permeability prediction based on pore throat group by using this methodology matches with measured core permeability with capture the complex respond of permeability variation. The result shows rock typing can be generated by using the pore throat distribution of the reservoirs. This is because permeability populated by this method captures the complexity of the reservoir. Results are more detailed by creating rock typing based on the pore throat. This is furthermore supported and incorporated with all available geological data. There is a significant difference that can be seen between platform, pinnacle, and complex carbonate. The workflow integrates critical information to further capture the complex carbonate reservoir system. This kind of approach is novel and should be adopted to the other carbonate reservoirs in the world for us to understand more on complicated carbonate reservoir structures or network. This study is robust and able to capture multiple carbonate environments and in comparison, with several basins from various parts of the world.