T-Field, located offshore East Malaysia, is a matured oil field that beganits development in the 1970s. Conceptual geological model generally illustrated this field as retro-gradational turbidite setting. The major reserves are contained in the stage IVD sequence, which is of late Miocene in age. The gross oil-bearing interval is about 300 m thick, divided into three(3) groups of sands (U -Upper, M-Middle and L-Lower stage IVD). As the "low hanging fruits" exist but are limited within this 40 years old matured field, drilling along the reservoir bedding plane was introduced as the best way to optimise the oil recovery in this field, where maximum reservoir-wellbore contacts and lower drawdown are expected to be achieved. It is commonly known that the turbidite channel has enormous geological complexity and therefore presents great challenges for successful horizontal well placement. The discontinuity of sand packages, highly anisotropic environment with the presence of thinly laminated sand and the lateral heterogeneities in horizontal zone are the biggest challenges in the implementation of this new drilling approach. Therefore, good well planning and right geosteering decision during drilling are crucial to achieve the well objectives. A reservoir mapping-while-drilling technology with capability to map the multiple sand layers in larger scale (up to 30m Depth of Investigation) was utilised to provide a clear picture of the reservoir structure during well landing and after entering the reservoir to stay inside the reservoir sweet spot for optimum production. This paper captured the first job in South East Asia in developing horizontal well placement in turbidities environment. It elaborates the highlights, success story and lessons learnt in using the latest technology which was proven as the most advanced geosteering and reservoir-scale mapping tool. This technology has not only enabled the drilling of 600 m-MD oil column, doubled net-to-gross ratio of sand penetrated and doubled the oil production of target reservoir but it has also helped the asset team in proper reservoir characterization and redevelopment planning.

This paper presents a case study of the first horizontal well in ADX field, Malay basin, which was drilled with an objective of maximising oil production from one of the minor reservoirs. In longer term, this well will be used as water injector once the reservoir pressure has been depleted, as part of the pressure management strategy in the field. To optimise the current production and the sweep efficiency at a later stage, a minimum of 500-m lateral length was planned for this well.The target reservoir contains gas cap without any aquifer and is currently produced with natural depletion. The plan was to place the horizontal well as close as possible to the base of the sand and as far as possible from the known Gas-Oil-Contact, to delay gas breakthrough and to use it as water injector at a later stage. An upper TVD limit was determined in which the wellbore should avoid to keep certain distance from the gas cap. However, the formation in the target location was expected to have a dipping-up trend, which could significantly limit the vertical space to steer the lateral section and achieve the minimum target length.A full suite logging-while-drilling measurement including deep directional resistivity which enabled 3D detection of approaching boundaries; combined with a proactive well placement method executed by collaborative experts from multidiscipline teams were used to address these challenges. As a result, the horizontal well was placed accurately within 0.5 m from the base of the reservoir along a 500-m lateral section; achieved with 3D geosteering decisions to avoid both the base and the upper TVD limit. Following the success of this first horizontal well in the field, another horizontal water injector well targeting a very thin reservoir was drilled successfully in the same field by applying similar methods and processes.

Some of the hydrocarbon-bearing sands in ADX field, Malay basin, have been identified as minor reservoir with an average sand thickness of less than 3 m. Thus, reservoir development has become challenging. One of the effective ways to develop these reservoirs is by drilling highly deviated or horizontal wells.After long production, one of the minor reservoirs in ADX has become highly depleted and was in critical need of pressure maintenance. Based on the field study, waterflood was chosen to manage the reservoir pressure. This reservoir is distributed widely in the field, with thickness ranging from 1 to 3 m. Because of the sand thickness, the most efficient method is to place an injector well horizontally. However, placing a horizontal well in this depleted thin sand poses significant challenges for the drilling operation. These include accurately landing at the target sand, avoiding premature exit due to geological uncertainties and the thin reservoir, and managing the borehole pressure to avoid differential sticking of the bottomhole assembly. For formation evaluation, high-angle effects such as anisotropy, close vicinity to shoulder beds, and lateral property changes complicate quantitative interpretation.A full suite logging-while-drilling measurements including near-bit gamma ray, average and deep directional resistivity for boundary detection, azimuthal density, neutron porosity, and formation pressure, combined with a proactive well placement method executed by collaborative experts from subsurface, drilling, and geosteering teams were used to address these challenges. As a result, an injector well was placed optimally in the thin target reservoir for a length of 300 m, as per the objective. Modeling of the high-angle well was also conducted to extract the true formation properties and to address the highangle effects on the measurements to improve the quantitative petrophysical evaluation. Comprehensive predrill planning, the drilling execution that included 24-hour real-time monitoring to steer the well, and post-well evaluation and modeling yielded lessons learnt, best practices, and recommendations for drilling and evaluating similar wells.

Deep and ultradeep azimuthal resistivity images enable precise well placement inside the reservoir structure. However, they deliver limited information about the quality of the reservoir, especially in carbonates, where large pore-size variations are common. Combining the deep and ultra-deep resistivity images with logging-while-drilling (LWD) nuclear magnetic resonance (NMR) measurements enables linking reservoir structure with rock types while drilling for optimal well placement. The NMR data is used to generate four petrophysical rock types while drilling: RT-1 has good porosity and long T2 components, indicating large pores; RT-2 has good porosity but medium T2 components, indicating smaller pores; RT-3 has medium porosity and long T2 components; and RT-4 has medium or low porosity and medium or short T2 components, indicating the worst facies. The first step in identifying these rock types is running factor analysis on the NMR data. This data analysis method is used to reduce a large dataset to a smaller number of underlying components. Used with NMR data, the method typically produces 9 to 11 factors and their associated poro-fluid facies, which are further reduced to four to ease interpretation. The method was implemented in two wells. The first had a single lateral, which was geosteered using ultradeep azimuthal resistivity images and NMR. The borehole entered the reservoir from the bottom. The NMR indicated a large section of RT-4, so the well was steered to cross into the upper reservoir lobe in search of better rock type. The best rock type, RT-2, was discovered at 8 ft true vertical depth (TVD) below the top of the reservoir, and geosteering continued within that rock type. The second well was a trilateral, geosteered with deep azimuthal resistivity imaging and NMR measurements. The initial lateral penetrated the first reservoir layer, where the NMR indicated RT-3 rock type with high permeability. After about 500 ft of drilling, the target reservoir layer was identified below the wellbore, and the well was steered into it. The NMR initially indicated that the rock type was RT-2, but combining the reservoir structure from the deep azimuthal resistivity image inversion with NMR rock typing confirmed that the upper section of the second layer had the best rock type, namely RT-1. Based on this finding, the second and third laterals were placed in the upper part of the same reservoir layer, with an excellent net-to-gross ratio. Association of NMR rock typing and reservoir structure while drilling is a new methodology that combines the strengths of both techniques to optimize reservoir understanding and well placement.

The Nong Yao Field in the G11/48 concession is operated by Mubadala Petroleum on behalf of the other concessionaires KrisEnergy and Palang Sophon Limited. Nong Yao recently commenced production following a successful development drilling campaign, which was extremely challenging due to subsurface uncertainties. The subsurface team adopted an innovative method of well sequencing and optimization of targets, such that every well drilled is used to de-risk other wells, in order to avoid costly additional appraisal drilling. The key methodology involved a deep understanding of the exploration and appraisal data gaps and as a result the uncertainties / limitations of the static and dynamic models. A field development plan was developed that could achieve additional appraisal objectives, and in doing so, de-risk other wells as the development was executed. Uncertainties that the team sought to mitigate included structural uncertainty (due to shallow gas effects), fluid contacts and fluid type uncertainty, sand distribution and connectivity uncertainty and also uncertainty in the aquifer extent and degree of pressure support expected. This information was gathered by planning deeper high deviation development wells with complex 3D trajectories, which could intersect multiple reservoir sands and provide the formation evaluation and well landing points for later horizontal development wells in shallower reservoirs. Achieving appraisal objectives while drilling both in the static and dynamic sense, helped in optimizing well locations and led to the cancellation of multiple water injection wells, which were not required as drilling indicated better aquifer and pressure support than initially expected. This led to substantial savings in well costs and enabled rig slots to be utilized for production wells rather than unnecessary injection wells. Key technologies were used to achieve appraisal objectives. A high build rate hybrid RSS tool was used to deliver complex 3D well profiles and land wells above oil-water contacts while maintaining high ROP and wellbore quality. The deep resistivity distance to boundary LWD tool ensured horizontal production wells stayed in the reservoir sands and also helped to map the top and extent of structures, improving reserves calculations and reservoir simulation. In key wells the use of the ultra-deep resistivity tool for reservoir mapping combined with the LWD near-bit triple combo, helped in mapping the reservoir prior to entering it, eliminating the requirement for separate pilot wells. The impact was that more marginal oil pools could be developed with a higher degree of confidence. The clear value of these innovations was a reduced overall development cost and wells better placed for recovery and production. With lower development costs, more reservoirs of this nature in the Gulf of Thailand can become viable to develop, which has a significant impact on the future of Thailand's oil and gas industry.