The well within the context of this case study consists of reservoirs are sequences of permeable sands interbedded with variable proportions of silt and clay. Gas is the target hydrocarbon type, but light oil / condensate can be present unexpectedly. In these depleted reservoirs, hydrocarbons typing are complicated by their reduced volumes and corresponding diminished effect on conventional logs. Wells are highly deviated and targets don't align in the same direction leading to high trajectories tortuosity. This prevents to plan extensive wireline logging program. Formation evaluation is mainly based on LWD logs. For such challenging condition, fluids identification is traditionally made possible by stationary Nuclear Magnetic Resonance (NMR) from wireline conveyed logging devices, adopting Diffusion— Relaxation maps technique. Through Diffusion—Relaxation maps technique, the contrast on both diffusivity and relaxation time (longitudinal relaxation time T1 or transversal relaxation time T2) allow differentiation of gas, oil and water. Even though high gas diffusivity creates contrast on transversal relaxation time T2 to differ gas from the other fluids, the approach based on T2 domain only is long time neglected. This is because under wireline condition, formation gas is often flushed by mud filtrate and the formation oil can be mixed up with OBM signal. This study proves that LWD NMR, due to its logging while drilling features, enables the simple T2 spectra based method to differ formation fluids in an efficient way. Attentive BHA design and job planning ensure good data quality and reasonably fast logging speed. Because of short time after bit (TAB) while drilling, it probes directly the formation fluids without being affected by mud invasion. For the studied reservoirs, the measured T2 value for water, gas and light oil are well distinguished being approximately of 200 milliseconds, 450 milliseconds and 2000 milliseconds respectively. The intervals with the presence of light oil are revealed directly from T2 spectra and the gas-oil-contacts (GOC) are accurately determined by T2 distribution. The same result is hard to be achieved by triple-combo measurements only. A newly introduced statistical technique "factor analysis" is used to determine poro—fluid distributions and associated porosities. It automatically searches for the dominant T2 modes through T2 depth log and identify repeated T2 distribution patterns to provide a continuous fluid facies analysis. Density Magnetic Resonance Porosity (DMRP) method is used to estimate the total porosity and gas saturation. It provides a resistivity independent method to address the gas saturation. Considering the fresh formation water, the uncertainty on the petro—physical parameters is significantly reduced. This paper divulges the value of T2 based fluid typing method with LWD NMR tool. It provides a simple but efficient way to identify gas from light oil. The fluid information offered is essential for field completion decision making.

Bulk density is a key petrophysical measurement that can be obtained from gamma-gamma density (GGD) and sourceless neutron-gamma density (SNGD) measurements. The unique SNGD measurement is new to the industry, having been introduced in 2012. A series of multi-functional LWD tools have been upgraded to include the option of acquiring density from conventional Cesium-137 (Cs-137) sourced gamma rays (GGD) and from electrically controlled pulsed-neutron generator (PNG) sourced gamma rays (SNGD). The two measurements are totally independent and can be acquired simultaneously. Multiple SNGD -GGD datasets have been compared from different fields in Southeast Asia to validate the SNGD measurement, providing confidence in the measurement in the study region. The extensive database includes the data from vertical to horizontal wells; different mud systems; limestone, sandstone and shale formations; and gas-, oil-, and water-bearing intervals. The results show excellent correlation between SNGD and GGD measurements. The average difference between the measurements is 0.001 g/cm 3 over the whole dataset. This is well within the SNGD measurement accuracy specification of 0.025 g/cm 3 for clean formations and 0.045 g/cm 3 for shale.The SNGD measurement has applications in all wells where there is a risk of losing bottom hole assembly (BHA) containing radioactive sources and in jurisdictions with tight nuclear regulations. There is strong interest in the measurement in the studied region, for several reasons: firstly, in development wells where variable depletion and shale instability are high risks; secondly, in exploration wells targeting deep zones with pore pressure ramps and very tight mud weight windows; thirdly, in long tortuous horizontal wells; and fourthly, wells risking total losses such as pinnacle carbonates. In addition, the multi-functional tool provides increased operational efficiency, higher rate of penetration (ROP) capability, significantly improved reliability throughout the system, and greater ease of maintenance. Replacing the Cs-137 source with a PNG significantly reduces the operational risks normally associated with the use of traditional LWD tools. By design, the PNG can be turned on only while pumping and only when several very restrictive safety conditions are fulfilled.The study results justify placing confidence in the SNGD measurement in high-risk drilling conditions.To date, the sourceless neutron-gamma density has been utilized standalone in more than twelve high-risk wells in the region.

The complexities of designing an effective sand control for unconsolidated gas reservoirs in a deepwater environment is exacerbated when the targeted formation sands are characterized by particle size distributions with poorly sorted and non uniform coeficients, and high fine concentrations. Managing these intricacies requires comprehensive sand retention studies developed to ascertain the effectiveness of the sand control performance of gravel and screen gauge opening combinations in the presence of selected formation sand ratios. To build a representative testing program, actual core samples from the targeted studied zones are desirable. However, for economical, technical or logistic contrains the availability of these cores is not always feasible. This paper covers a workflow to determine a synthetic Particle Size Distribution (PSD) of a targeted well in a development block where no core data is available. The data feeding the workflow is derived from wireline bore hole imagers and Non-Magnetic Resonance (NMR) logs obtained from six wells drilled in the exploration phase of the studied gas block. Results are calibrated with localized PSD from available side wall cores. Furthermore, data obtained from the process is used to interrogate sand retention testing Mastercurves built with formation samples from one of the fields in the studied block (Field I). The interrogation process takes the synthetic PSD from the targeted well and creates normalized formation testing ratios which are then compared to the results documented on the sand retention Mastercurves. This paper is intends to discuss the worklflow and results of its field application.

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.