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.

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Gas fields in a Malaysia-Thailand joint development area (MTJDA) are well-known to have the presence of high CO2 concentration and high-temperature reservoir characteristics. Sophisticated tools are necessary to measures important data to support further development and reservoir management of this field. Thus, reservoir data, such as pressure and fluid type, become crucial in terms of achieving production targets. Fields operated by this operator are located in the North Malay Basin, a few hundred kilometers from the onshore border of Malaysia and Thailand. High bottom hole temperatures (BHTs) limits data gathering runs and challenges associated with fresh water made it more crucial to identify and qualify fluid types for further field development. The extensive wireline formation pressure testing and sampling (WFPT&S) program is mandatory to evaluate the viability of field development. Additional challenges included low porosity-low mobility reservoirs where fluid collection at low contamination in reservoirs with elevated temperatures of approximately 410°F (210°C) is considered a necessity. This operator pioneers the use of novel hostile wireline formation testers globally. Reliable pressure and downhole fluid analysis data should lead to production optimization. The ability of fluid characterization using a pump-out formation tester coupled with downhole fluid identification has been introduced to help improve decision making and provide real-time data and the capability to pump out high-temperature formation fluid and acquire samples that meet expected contamination levels. As a result, fluid contact, formation pressure, fluid type, reservoir mobility, and CO2 content, which are the primary drivers of production optimization and field development are able to be determined successfully. In addition, new deep reserves could potentially be discovered in the MTJDA concession that are economically accessible with extreme high-temperature tools. This paper discusses the use of a novel hostile wireline formation tester to collect low contamination samples at a predetermined level in hostile reservoir conditions with elevated temperature of 410°F (210°C). Challenges, considerations, and results are detailed. This novel tool has proven lower CO2 content than expected in deeper reservoirs with elevated temperature up to 410°F (210 °C). This is the deepest well ever drilled by this operator in a development drilling campaign.

Sampling in a highly deviated well involves additional risks that can compromise efficiency and costs. Operators and service companies have developed options to overcome the technical challenge of going from tubing-assisted logging to tractor-conveyed operations. Tubing-assisted logging will mitigate the issues and stuck risks caused by wireline key seating, differential sticking, swelling formations, heavy muds, borehole breakout, doglegs, ledges, and cuttings but will require slower operations resulting in additional rig time and therefore costs. Tractor conveyance, on the contrary, can be efficient but will add costly operating rates and higher cost exposure if the tools are lost in hole. An operator in offshore Southeast Asia had an objective to perform formation evaluation by means of pressure tests with pump out to obtain clean samples for CO2-level measurements in a slim well geometry (6 1/8-in. hole) with 73° deviation. Sampling wheels that configure with the wireline formation tester tool were introduced to the operator to reduce the contact area, keep the tool body off the low side of the borehole wall, and aid gravity descent. The operation objective was successfully accomplished and reached the target depth (TD)/reservoirs by performing five pressure tests, setting up three fluid characterization stations, and retrieving six samples in approximately 12.5 operating hours, resulting in savings of more than USD 350,000 for the operator.

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