During field testing of a logging-while-drilling (LWD) laterolog resistivity and imaging tool, formation resistivity differences were observed between the new laterolog and standard propagation resistivity. This paper compares the resistivity measurement acquired in the same borehole using different tools in both sand and shale formations. In addition, the high-resolution images acquired by the new tool are used for a detailed geolgical analysis of the sequence. The high-resolution images acquired by the tool are used to determine the sedimentary environments in this complex fan delta sequence. A wide range of facies types can be identified on the images and correlated to available core with detailed examples shown of the key reservoir facies (distibutary channels and mouth bars). The images also provide valuable structural, depositional trend and insitu stress information for this well. The laterolog resistivities were higher in the shales and lower in the sands than the propagation resistivity values. The data was acquired while drilling in a water-based mud, sub-vertical exploration well in the South China Sea. While the main objective of the data acquisition in the siliciclastic formations was high-definition resistivity borehole images for detailed geological description, the radial laterolog resistivity response was also of interest. An advanced wireline multi-frequency dielectric measurement was also acquired, and its response was used for comparison and validation. In this paper, we associate the differences in resistivity response for varying formation properties to the tool physics, vertical resolution, depth of investigation, and time after bit between the measurements. In the sands, a resistivity inversion was applied to correct the logs for invasion effects and forward modeling used to resolve the resolution differences. The inverted formation resistivity from the LWD laterolog matches the deeper reading LWD propagation resistivity. The shale response was initially found to be more difficult to explain. It is commonly and historically accepted that due to resistivity anisotropy laterolog reads higher than propagation resistivity in low angle wells with laminated formations. Advanced forward modeling was used to investigate the laminations observed on the high-definition images and high-resolution laterolog resistivity curves. Although a model could be created to match both sets of resistivity measurements, the level of anisotropy required was considerably higher than expected, and supplementary information was required to validate the model. The wireline multi-frequency dielectric measurements provided the additional information required to confirm the anisotropy contrast observed by the resistivity modeling and confirm the LWD tool responses. This paper will compare the tool responses, and to determine the correct sand and shale resistivity. It will show how by combining different measurements, additional insight can be obtained into the nature of the formation and its properties.

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An accurate pore-pressure prediction plays an important role in well planning as exploration targets shift to deeper over-pressured reservoirs. Pore pressure related problems in high-pressure high-temperature (HPHT) wells include well control, lost circulation, formation breathing, differential sticking, reduced penetration rate, and reservoir damage, many of which can potentially lead to expensive sidetracks, underground blowouts and early well abandonment. An integrated approach can help with better understanding the pore pressure regimes, including generating mechanisms as well as pressure preservation and dissipation processes through geologic time. This improved understanding provides invaluable insight into the different drilling challenges and the strategy to mitigate or minimize pore pressure related problems. Once the pore pressure model is established, the in-situ stress tensor needs to be constrained following a well-developed geomechanical modeling workflow. Both the pore pressure and in-situ stress models are required for wellbore stability analyses to understand wellbore failure mechanisms as well as the design of optimum mud weights. Additional considerations include drilling through faults, which due to the field's unique structural characteristics could further complicate the already difficult drilling condition in a HPHT environment. This paper presents a case study to highlight the utilization of an integrated approach for pore pressure prediction to reduce drilling risks and costs of a HPHT well located in South China Sea. Prior to drilling, the major risk anticipated for this well, which was required to explore a deep-play at 5 Km MD, was high-pressure (1.53 sg at 4800 m TVD) and high-temperature (172 ºC at 4800 m) with narrow margin drilling conditions. Geomechanical studies that include both pre-drill and real-time (RT) drilling components provided inputs for effective well designs and drilling operation supports. Compared to the drilling of an offset well which had to be prematurely terminated due to continuous high total gas encountered despite increased mud weights, the planned well was successfully drilled to the target zone with no issues even drilling at high rate of penetrations (ROP). This new drill was the best well ever recorded in the block. The adaptation of the integrated approach in pore pressure prediction has successfully reduced the occurrence of borehole instability related problems and the associated non-productive time (NPT). The drilling performance and well delivery efficiency of future wells will improve with additional operational experience and geomechanical understanding obtained from additional drilling. This continuous learning process will be the key aspect of this project, ultimately contributing to the overall success of the field development.

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As oil and gas exploration and production extends to deeper buried reservoirs, challenges such as lower porosities and Ultra High Temperature have been encountered. Several reservoirs in the Asian region, the North Malay basins in the joint development area between Thailand and Malaysia, and the Baiyun Sag and Qiong Dongnan basin in offshore China are considered to have the highest known temperature gradients due to their geological depositional system and hydrocarbon charging mechanism. More than fifty percent of wells drilled in these areas have temperature close to/or higher than 170 degC, and some reach above 200 degC. In number a of projects in these areas, the logging requires tools that can withstand up to 230 degC. Traditional, wireline Formation Testers (FT) with fixed rate and volume pre-test and old sampling technique using a dumping chamber (i.e. without pumping capability) had been the standard formation tester when temperatures reached 400degF (204 degC) and higher. The tools were not flasked and therefore, the temperature transient affected the quality and accuracy of pressure data1,2. Also, in such harsh environment, it is very difficult and time consuming to go back to a good mobility station for sampling after pressure measurement, due to reservoir heterogeneity and depth error. This paper discusses a project for a new slim hole ultrahigh temperature Wireline Formation Tester designed to obtain both pressure profiles and perform downhole Pressure Volume Temperature (PVT) *Trademark of Schlumberger fluid sampling with pump-out capability and downhole fluid sensors such as viscosity, density and resistivity in extreme HT environments. In addition, this slim hole ultrahigh temperature tool dimension has more clearance between the tool and formation, and therefore, less chance of having this tool get stuck during slim hole logging. The tool was first deployed in the North Malay Basin and since early 2018, new well head platform with five development wells were logged where a total of 76 pre-tests, four pump-out and ten fluid sampling stations were conducted. The main objectives for this FT tool were to obtain formation pressure, identify reservoir fluid and quantitative CO2 measurements zone by zone. The results will be discussed operationally and technically, in terms of data quality and accuracy and compared with on-site surface analysis. In addition, this tool improves significantly operationally compared to the previous tools and with some operators having mixed perceptions on running Wireline FT tool with bigger ODs, especially drilling departments, having this new slim hole with its smaller OD increases their confidence level in running it. For Deepwater Offshore China, an operator has been facing challenges to explore a brand-new block such as pore pressure distributions profile, reservoir quality, and extended logging period. The main objectives for the extreme FT are to obtain the formation pressure for drilling purpose, to understand reservoir potential to optimize the perforation interval for Drill Stem Test, and to narrow logging operation time window due to seasonal weather. This new ultra-high slim hole was therefore proposed to log in this challenging environment. This field example shows a significantly improved pre-test and sampling capability in the lower mobility ranges, which some previous generations of formation testers had struggled with in the past, in one run and without sacrificing testing efficiency The effective time for valid pretest can be achieved even in the range of mobility 0.01 mD/cp, high pressure of > 11000 psi, and high temperature of >180 degC. This paper discusses pre-job planning and actual job execution results in both locations. The challenges of logging and lesson learned are addressed. This is the first attempt in evaluating reservoirs in the deeper and HT sections to properly understand reservoir fluids.