Fluid identification is a key component of formation evaluation and becomes one of the important parameters that underlie economic decisions in field development. The combination of high clay content in the thinly laminated shaly-sand reservoir, together with unknown water salinity, increases the complexity in the accurate quantification of hydrocarbon-bearing reservoirs. The inherent clay distribution affects the log data response of high gamma and low resistivity analyses. Those responses can lead to incorrect interpretations unless other log data responses are considered. The low resolution of a common oil-based resistivity tool often fails to capture structurally complex, thinly laminated sand-shale formations. The low resistivity response results from high resistivity sand layers suppressed by low resistivity shale layers, which can result in misinterpretations of calculating high water saturation. Observations of other conventional well log data can provide early qualitative identification of the low contrast zone. Data from the Thomas-Stieber method, resistivity anisotropy, and high-resolution micro-imaging are available to reconstruct conventional log data to provide an enhanced vertical resolution for final interpretations. A field study was performed in the North Malay basin. Geologically, the field has three-way dip closure, bounded by a west-dipping fault to the west. The early evaluation of the DS2-B layer was interpreted as shale zones following a high gamma and low resistivity reading. Further observation of the density, neutron, and shear sonic trend do not provide the same shale indication. The decision was made to run a formation tester tool and to investigate any possible hydrocarbon indication. Real-time fluid identification and sampling proved the DS2-B layer to be gas-bearing and indicated that the conventional petrophysics-calculated water saturation was too high. Three petrophysics re-evaluation approaches were performed to define the reservoir challenges, including deterministic, Rv/Rh methods, and high-resolution data approach to obtain a better definition. All available data were used on the methodologies, based on the data required for each method, particularly the use of high-resolution imaging and core data for conventional logs to define the high-resolution of porosity, clay volume, and water saturation. As a result of these analyses, the DS2-B layer was proven to be a pay zone with a lower water saturation, which correlated with the formation sampling and core analysis results. The methodology has a proven capability to identify low contrast zones and can provide better interpretation in the field study through providing more a precise and accurate net-to-gross calculation. The correlation and calibration of the conventional well log data to high vertical resolution image log, core data, and fluid sampling have provided a means of better visualizing and understanding the features of thinly bedded reservoirs in the field study. All methods were performed to calculate the final fluid saturation in highly laminated reservoirs. The new interpretation has proved a significant contribution to the NM field economic value.

To develop a field with combination structural and stratigraphic trap style is always challenging, especially with trap uncertainties that are coupled with limited exploration and appraisal wells. The potential production shortfall or non cost effective development plan would be an issue if the number and locations of the wells are not carefully selected. Thus, a comprehensive reservoir modeling study, both static and dynamic modeling was designed and instituted to integrate all available information and geological concept. In the Muda South Central (MSC), which will be discussed further in this paper, structural re-mapping was conducted to refine the trap and structural style. However, the plunging nose structural styles do not have a closing contour to the north of the field, which requires interpretive arbitrary boundary to isolate the compartment and to limit the field boundary. The nearby field in the northern part has a four way dip closure which proves to have a different fluid system with the studied area. Concurrently, a geological facies modeling study was generated using regional trend knowledge and guided by seismic attribute qualitatively. Reservoir trend direction has played an important role in hydrocarbon trapping. The high uncertainty of reservoir presence was assessed by including inputs of low and high extremes sand-shale-ratio in facies modeling exercise for the purpose of capturing reservoir uncertainty. In dynamic simulation, Simulation Opportunity Index weighted with Gas Initially In Place (GIIP) map is considered to identify sweet spot location. This enables the subsurface team to optimize the number of development well and the placement of the well at the ‘sweet spot's location. Water and sand production prediction is taken into the consideration to minimize the impact to well performance. Subsurface uncertainty analyses were performed which includes sand distribution, fluid contact in vertical and lateral extension, rock & fluid properties, aquifer strength and well performance. The uncertainty of the number of development wells was anticipated by performing multiple simulations for low and high case. The model is intended to be used as a guidance to subsurface team for decision making during the development drilling campaign.

Finding an opportunity to expand the recoverable reserves in a brown field is always a challenging task. A robust reservoir characterization and dynamic synthesis are vital to provide a proper understanding of the field. The objectives of this project are to maximize gas recovery through 3D reservoir modeling works, to evaluate un-connected hydrocarbon volumes, production improvement, and prudent reservoir management. Muda Central field (MCF) has been producing for more than 5 years with 40 production wells. Therefore, the production data is an essential input to assure the quality of the model. The geological-facies modelling was constrained by seismic attributes as quantitative soft data after calibrating to well data. The high uncertainty of reservoir presence in the model was assessed by combining sand distribution and porosity variation. Material balance analysis was used to select a base-case static model in order to reduce the iteration process during the history match. History matching was performed with a reasonably good match to calibrate the model. The results of dynamic simulation indicated some potential undrained hydrocarbon areas that are promising for future development. As a result, one well was proposed to appraise and prove the existence of disconnected hydrocarbon volume as recognize in the seismic attributes. The well was drilled a year later to prove the hypothesis. The drilling result demonstrates that the initial hypothesis is proven by pressure data and fluid sampling. The reservoir pressure is still un-depleted and the level of CO2 content is different compared to the existing producing wells. This finding provides an opportunity for future development in the vicinity of the existing producing platform as well as a different development scheme in the area of the appraisal well. The additional benefit of this work is to assist with prudent reservoir management. A comprehensive model of MCF demonstrates a best practice, collaborative interaction between geophycisist, geologist, and reservoir engineer. This study successfully proved disconnected hydrocarbon volume, which translates into a future development plan to optimize MCF reserves.

In the event of high gas demand, infill well drilling is one of the best option to increase gas deliverability. Finding infill well opportunity in a brown field is a challenging task. Reservoir continuity, heterogeneity of the rock properties, pressure depletion and identifying undrained area are the major concern for infill wells candidate selection. A robust reservoir characterization and dynamic information are essential to provide some key understanding about the field. The area of interest, Muda field, is located in the Block B-17 of Malaysia-Thailand Joint Development Area (MTJDA) which has been producing for more than 5 years. Integration of multidisciplinary data is very important to identify the potential hydrocarbon bypassed area. To start with, the geological model was built and constrained with seismic attributes after calibration to the well data. The high uncertainty of reservoir presence in the model was assessed by combining the sand distribution and porosity variation. Subsequently, history matching was performed to calibrate the model with actual production flow rates and reservoir pressure. A reasonably good history match was achieved and provides a certain degree of confidence in production forecast. As a result, it shows some potential undrained areas to be selected as the area of infill well candidate. The infill wells were drilled within 1 to 2 years later and the well results has demonstrated a successful delivery of infill well as expected both in encountered netpay and production. This paper discusses a successful collaboration between multidisciplinary team members in the subsurface division to deliver infill well candidate by building a comprehensive reservoir model which integrate of all hard data from geological concept, seismic attribute, well and production. Five successful infill wells were drilled in accordance to this campaign, expected potential and volume are generally as expected with some surprises in some interval. The gas potential comes from these infills are very important to fulfil gas deliverability. It is foreseen that additional infill wells are expected and evaluated using the 3D reservoir model.

Field X, located in the offshore Malaysia-Thailand Joint Development Area (MTJDA), comprises multiple stack gas reservoirs with a combination of trap styles. This paper highlights the challenges and lessons learned in successfully developing the deepest Oligocene syn-rift sediment in the MTJDA, which was initially discovered by the one appraisal well drilled in 2010. A further comprehensive evaluation was performed to justify the deepening of development drilling in 2019 (as appraisal cum to development) and 2021-2022 (as infill wells) with promising results. The discovery of hydrocarbon resources in the deepest Oligocene syn-rift sediment at MTJDA was part of an appraisal program by deepening the development well. The two wells discovered and proved the presence of multi-stack gas sands in this deepest section (3800-4000 mTVDSS). The clastic sediment deposits in a fluvio-deltaic system. The reservoir properties of this syn-rift sediment are better than the early post-rift sediment (early Miocene). The production test confirmed the initial gas flow rate of about 15 MMscfd. A comprehensive analysis was performed to evaluate a sizeable volume before more development wells were proposed for this deepest sediment. The initial understanding of Late Oligocene syn-rift sediment was very minimal at the beginning of the project. One of the neighbouring well information suggests lacustrine delta environments based on core data. However, a fair-quality seismic amplitude shows a broader channel belt (over 3km width) which usually exists in the braided stream. In view of the two appraisals cum to development wells' successful discovery, more than five wells were proposed to penetrate this zone as a deepening target from the existing discovered zone. The fit for purpose well designed with a monobore concept, was selected. Upon completing the development drilling with denser well spacing, it suggests the discontinuity of blocky sand presence with multiple fluid contact (stratigraphic compartmentalization), which is usually found in narrower channel reservoirs at the deltaic system rather than the braided stream. The good reservoir properties observe from the open hole log, formation tester, and production test. The success story of these wells opens future opportunities to plan more deep well to develop Oligocene sediment, which prove to be a good hydrocarbon producer. This paper updates the previous understanding of geology, such as the depositional environment, and the understanding of reservoir productivity of the Oligocene sediment in MTJDA. It also proved sizable reservoir quality with extensive lateral presence and good productivity. Hence, the company foresee a promising future from this deep reservoir to prolong its long-term development plan.