Laminated units made up of alternating thin sand and mud layers are known to be very challenging in terms of reservoir characterization and evaluation. Alternation of thin sand and mud layers imposes natural anisotropy in the distribution of reservoir properties such as porosity and permeability. This anisotropy has been proved to be a major control on fluid flow within the reservoir which is of paramount importance to understand and consider in reservoir development planning. The aim of this work is to integrate geological information derived from borehole images into interval pressure transient test (IPTT) interpretation to analyze and explain the complex flow behavior resulting from a combination of formation dip and laminations.A wireline formation tester dual packer module was utilized in two offshore exploration wells to conduct an IPTT/miniDST (mini Drill Stem Test) in different lithofacies including laminated units. Several build up tests were performed to obtain valid reservoir pressure and permeability values. Consistency was observed in the log-log diagnostic plot from these build up tests and the pressure derivative behavior suggests multiple possible reservoir scenarios in this complicated geological setting. A detailed study on borehole images and 3D near-wellbore geological model revealed the effects of slanted wellbore, laminated units and dipping beds on the travel of pressure transient away from wellbore. With this information, a representative reservoir model was able to be constructed to match the IPTT data and to obtain the required reservoir parameters.This paper highlights the main challenges of formation characterization in laminated thin sand and mud layers. Special emphasis was given to resolve significant problems encountered in pressure transient test interpretation in highly deviated wells. Slanted wellbore sections are typical in Malaysia's offshore fields as the wells are drilled from offshore platform to intercept the formation at different angles, hence the pay zone and other petrophysical parameters are usually underestimated. Attempts are made to identify and classify these challenges, and recommendations are provided toward better resolution during interpretation.

Since early 1990's, Downhole Fluid Analysis (DFA) has been developed to monitor mud filtrate contamination for Wireline Formation Tester downhole sampling. DFA can also provide accurate reservoir fluid information in real time such as hydrocarbon composition including CO2. However, DFA technology cannot measure Nitrogen because N2 has no absorption in the Near Infrared Region (NIR). Therefore, it cannot be directly detected with any spectrometer measurement downhole. This paper will present innovative methods that can be used to predict the amount of N2 in each reservoir. These new techniques can help many clients in the EAG and as well as other basins to accurately quantify N2 without the need to wait for PVT laboratory analysis which generally takes several months to complete. Detection of non-hydrocarbon gases in oil and gas fluids, such as nitrogen gas, is very important for reservoir assessment and management. N2 content affects reserve estimation, especially in the area where reservoir fluids have high N2 contents. In our experience, there are several basins in Asia where N2 and CO2 coexist in the same reservoirs. N2 was charged into reservoirs from the source rock in the same geological time as Hydrocarbon (HC). The CO2 then later charged into the same reservoirs. Xu et al (2008) and Mullins (2019) suggested that the ratio of HC. and N2 are in proportional for each basin. However, the CO2 which was later charged are variable in each reservoir depending on CO2 source and charging area. The relationship between HC. and N2 can be used to predict amount of N2 using three proposed methods (1) Basin Base Method (2) Iteration Methods using DFA spectrometer and InSitu Density measurements., and (3) Equation of State (EOS) Method. This nitrogen prediction techniques were developed to better characterize reservoir fluids and overcome the limitation of the existing technology that's unable to detect and measure nitrogen at downhole conditions. This method can offer extra information, especially for our new Ora Intelligent Wireline Formation Tester technology where answer products will be expanded to tailor client objectives. The N2 and HC. relationship from each basin are examined in detail from our DFA and PVT data base. The ratio of N2 and HC. were then recorded as initial value for Basin Base Method. Then the second N2 prediction technique that uses individual hydrocarbon compositions and downhole density measurements were conducted to calculate missing N2 mass from spectrometer measurements. A ternary diagram was prepared to visualize and determine correlation of the gas composition components. It was found that straight line can be obtained on the Ternary diagram between N2, HC., and CO2 for each reservoir. A detailed calculation based on fluid components and partial densities together with iteration process allows to estimate the mass percentage of nitrogen. The results were then compared with actual value from PVT lab. These nitrogen prediction techniques already have been tested and validated using various datasets from South East Asia and other. This technique can be extended to be part of Reservoir Fluid Geodynamic (RFG) to evaluate lateral reservoir connectivity and to better understand CO2 and N2 charge to reservoirs.

Reservoir fluid characterization is crucial for the success of field exploration and development phases. Early detection of hydrocarbon allows accurate determination of reservoir fluid properties and plays a key role in reducing uncertainty in reservoir evaluation and future field development strategies. Advanced Mud Gas logging (AMG) system and wireline downhole fluid analysis are among the important means available in the oil and gas industry for such analyses. Each method has its limitations and advantages, therefore developing an integrated approach and workflow that combine these two different methods are important for the success of fluid sampling and for better reservoir characterization.The aim of this integration work is to improve reservoir fluid evaluation during the entire well starting from the early stage of drilling. This can be done by having reliable early hydrocarbon detection from mud logging which allows optimizing formation PVT sampling program, and helps to develop correlations for the benefit of fluid evaluation in future wells.This work presents a successful integration of mud logging and downhole formation fluid analysis for better reservoir fluid characterization in an offshore Malaysia field. Advanced Mud Gas logging was run to provide early formation fluid evaluation, which was utilized to design and optimize formation fluid sampling, PVT lab work and further DST requirement. By using AMG, it was possible to identify the significant changes observed on fluid composition (C1-C5, C6-C8 range) and also to distinguish potentially fine variations within the possibly same fluid type. Based on these results detailed fluid evaluations and sampling points were suggested. In addition several potential hydrocarbon/water contacts were identified. Wireline formation tester (WFT) was also run for downhole fluid identification (DFA) and to acquire representative fluid samples in addition to reservoir pressure and fluid mobility. This paper also presents strategies used for fluid analysis and sampling to provide accurate fluid characterization in a challenging environment. The methodology, workflow, analysis, and applications of this field study are presented in this work.

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Evaluating hydrocarbon columns, reservoir fluid types, contacts and productivity has been challenging in East Asia, especially when open hole well challenges are encountered. Initial openhole attempts are at times unsuccessful in proving significant hydrocarbon potential mainly due to severe losses, high differential pressure or bad hole conditions. The need for a new formation evaluation strategy became necessary to secure critically needed data for the prospect evaluation. The objectives, apart from establishing the presence of hydrocarbon column, is to optimise well drilling execution in a safe and timely manner. In addition to losses challenge, wells encounter hole stability issues with shale being overpressured and potential presence of H 2 S, whereby its level need to be determined onsite for completion strategy.To meet the objectives of these wells, an alternative formation testing and sampling strategy has been adapted. The reservoir fluid evaluation was postponed until the open hole was cased. The formation evaluation with Wireline Formation Tester (WFT) was performed in two stages, the first stage was to confirm the presence of cement isolation at the hydrocarbon intervals, and the 2nd stage was to perforate intervals at the zones of interest to confirm the hydrocarbon columns by downhole fluid analysis and sampling.This case study will discuss reservoir rock and fluid evaluation in cased hole with WFT. Reservoirs of interests are successfully evaluated and representative samples are successfully acquired without any operational issues. Recommended evaluation strategy and best practice supported by field data will also be presented in this paper