A deepwater turbidite formation from Eastern Offshore, India, is a major focus for hydrocarbon exploration. The reservoirs in this field are primarily of low resistivity and low contrast and consist of thinly laminated shale-sand laminae with overlying thick shales. Conventional logs do not sufficiently distinguish between the overlying shales against the laminated reservoir intervals- owing to poor vertical resolution of the tools to characterize the thin beds properties. A standard practice followed by the operating company was acquisition of conventional logging data along with tensor resistivity measurement for a laminated-shaly sand analysis (LSSA) followed by formation testing. While multiple new pay sands were discovered through this method, the sand-shale-fluid model of LSSA is insufficient to provide fluid typing. Furthermore, fluid sampling using formation testers in these unconsolidated formations are risky due to relatively high SOBM invasion and therefore high clean-up time is required to collect samples. Due to the similar properties between the SOBM and formation oil, it is difficult to conclude between the two fluids during real-time monitoring. Thus, it was essential to delineate the formation fluid using methods other than formation testing. The acquisition of magnetic resonance data and an integrated interpretation involving conventional logging, tensor resistivity and NMR data helped overcome these challenges, prior to formation testing. The electrical anisotropy and borehole image data helped identify thin beds. LSSA outputs based on conventional and tensor resistivity data indicated hydrocarbon bearing intervals. A continuous magnetic resonance measurement acquiring the longitudinal relaxation (T1), transverse relaxation (T2) and the diffusion coefficient (D), helped derive a lithology independent fluid typing in these wells to provide insights before formation testing. Hydrocarbon bearing sands were identified as per the results of the integrated analysis, and the formation testing intervals were optimized. Conventional resistivity inversion, LSSA saturation and flushed zone saturation from magnetic resonance provided an understanding of the invasion. The hydrocarbon bearing intervals delineated from integrated formation evaluation using LSSA and 2D NMR analysis were successfully tested and proven using formation testing and sampling. Subsequently, the exploratory well logging programs were modified to include the magnetic resonance in future wells and the workflow explained herein was adopted field-wide. This paper provides a framework for integrated data interpretation using multi-component induction, magnetic resonance, acoustic data and resistivity imager logs to quantify reservoir fluids and subsequently provide an alternative to formation testing and provides a workflow for exploratory wells for Eastern Offshore, India.

Several challenges are associated with reservoir characterization of organic-rich, unconventional plays, most significantly with estimating producible hydrocarbons and identifying potential zones to land horizontal wells and subsequent stimulation. This paper illustrates integrated approach towards successful characterization of the Cretaceous carbonate major source rock-a lateral seal Shilaif formation in the recently developing area of syncline shape field in Onshore UAE. The Shilaif formation that was deposited under intra-shelf basinal conditions, contains sediments of argillaceous limestone, mostly fine-grained packstones and shaly lime mudstone-wackestones with subordinate calcareous shales in the lower part. Presence of bitumen and low permeability indicate the requirement to stimulate the wells effectively. Quantification of bitumen and light hydrocarbon through integration of advanced and conventional log data with core data and mud logs plays a critical role in the evaluation and development of these organic-rich reservoirs. Extensive data acquisition was planned with a wireline suite that included resistivity/density/neutron/spectral gamma ray; acoustic logs; resistivity image; nuclear magnetic resonance (NMR); advanced elemental spectroscopy; and dielectric technologies to characterize the hydrocarbon potential of organic-rich Shilaif unconventional play. NMR and Spectroscopy were used to refine lithology and porosity, which reduces the associated uncertinity in the evaluation of total organic carbon (TOC) and volumes. The advanced elemental spectroscopy data provided the mineralogy, the amount of carbon in the rock, and consequently the associated organic carbon within the Shilaif formation. The NMR technology provided lithology-independent total porosity and moveable versus non-moveable fluids quantification when integrated with density/neutron. NMR technology in this present case study was used to identify and differentiate the organic matter and hydrocarbon presence within the Shilaif formation. The water filled porosity and textural parameter from dielectric inversion results helped in more accurate water saturation estimation in the tight formation. Acoustic data results and high-resolution resistivity image logs were used to evaluate the geomechanical properties. In addition, Resistivity image data provided detailed knowledge of geological features, faults and natural fracture networks within the study zone to enable optimization of development scenario based on the reservoir properties. The data integration work illustrated in the paper is a key for unconventional reservoir characterization that enabled identification of the potential zone/zones of interests for horizontal wells and the successful development of the organic rich rocks of the Shilaif formation.

Conventional volumetric analysis has its own limitations & challenges to characterize fluid types in complex clastic reservoirs. Presence of shale and radioactive minerals in sandstones makes the evaluation more complicated compared to clean reservoirs as uncertainty become higher to ascertain grain density & total porosity. Delineation of pay zones (heavy oil bearing) & estimation of saturation become more uncertain due to reservoir complexities. Elemental spectroscopy log can provide real time grain density, TOC (Total Organic Carbon) and mineralogy for complex reservoirs (radioactive sand). However, to determine the fluid type and porosity in this type of reservoir, Nuclear Magnetic Resonance (NMR) would be the best choice due to its capability of recording simultaneous T1 (Spin-lattice relaxation time) and T2 (Spin-Spin relaxation time) including diffusivity measurement sequences. Compare to the traditional 1D T2 spectrum based interpretation methodology; A new approach of using constrained 2D NMR inversion, enhances the capability to discern different fluid phases by mapping proton density as a function of T2 relaxation time (T2int) in the first parameter dimension and diffusion coefficient "D" (or T1 relaxation time or T1/T2app ratio) in the second parameter dimension. An integrated approach is used by combining NMR and Elemental spectroscopy results to reduce formation evaluation uncertainties in heavy oil reservoirs. Successful integration of NMR, Elemental Spectroscopy Log with Image and Acoustic results helps to understand reservoir properties in study area. The advantage of using constrained 2D NMR over conventional 2D NMR reduces the uncertainty of responses between Clay Bound Water (CBW) and heavy oil, which has similar T2 relaxation mechanism. Integration of Clay volume from Elemental Spectroscopy measurements in constrained 2D NMR helps to differentiate the heavy oil and clay bound water responses. Furthermore, the combination of NMR & Elemental Spectroscopy results helps to segregate the existence of heavier oil & lighter oil components in the reservoir. Based on these results, potential hydrocarbon zones was identified and successful testing attempts were made. This paper shows an approach of using constrained 2D NMR results over conventional 2D NMR to overcome reservoir uncertainties & to identify potential pay zones.

Drilling wells in the remote northeastern part of India has always been a tremendous challenge owing to the subsurface complexity. This paper highlights the case of an exploratory well drilled in this region primarily targeting the main hydrocarbon bearing formations. The lithology characterized by mainly shale, siltstone and claystone sequences, are known to project high variance in terms of acoustic anisotropy. Additionally some mixed lithological sequences are also noted at particular depths and have been identified at posing potential problems during drilling operations. Several issues became apparent during the course of drilling the well, the main factor being consistently poor borehole condition. An added factor potentially exacerbating the progressively worsening borehole conditions was attributed to the significant tectonic activity in the area. To address and identify these issues and to pave the way for future operations in this region, a Deep Shear Wave Imaging analysis was commissioned to identify near and far wellbore geological features, in addition to addressing the geomechanical response of these formations. In this regard, acoustic based stress profiling and acoustic anisotropy analysis was carried out to estimate borehole stability for the drilled well section and provide insights for future drilling plans. Significant losses were observed while drilling the well, in addition to secondary problems including tight spots and hold ups and consequently the well had to be back reamed multiple times. Of particular note were the losses observed while transitioning between the main formations of interest. The former consisting relatively lower density claystone/siltstone formations and the latter, somewhat shalier interlayered with sandstones, displaying a generally higher density trend. This transition zone proved to be tricky while drilling, as a high density sandstone patch was encountered further impeding the drilling ROP. Overall, both formations were characterized by significantly low rock strength moduli with the exception of the sandstones projecting characteristically higher strengths. In light of these events, analysis of integrated geological, geomechanical and advanced borehole acoustic data analyses were used to identify the nature of the anisotropy, in terms of either stress induced, or caused by the presence of fractures in the vicinity of the borehole. The extensive analysis further identified sub-seismic features impeding drillability in these lithologies. Further, the holistic approach helped characterize the pressure regimes in different formations and in parallel, based on corroboration from available data, constrained stress magnitudes, indicating a transitional faulting regime. Variances in stress settings corresponded to the depths just above the transition zone, where significant variations were observed in shear wave azimuthal trends thereby indicating the presence of potential fracture clusters, some of which were revealed to be intersecting the borehole thereby causing stress. The analysis shed light on these near well fractures- prone to shear slip, causing mud losses during drilling while drilling with high mud weights. Finally, the encompassing multiple results, an operational mud weight window was devised for the planned casing setting depths. Given the presence of numerous fractures, the upper bound of the operational mud window was constrained further to account for the presence of these fractures. In summary, an integrated approach involving a detailed DSWI study in addition to traditional geomechanics has brought about new perspectives in assessing borehole instability. By actively identifying the sub surface features, (sub seismic faults and fractures) decisions can be taken on mud weight and optimizing drilling parameters dynamically for future field development.

Geomechanics has an important role in assessing formation integrity during well construction and completion. It also has its effect when the wellbore is in production mode. Geomechanical study evaluate the impact of the present day in-situ stress and related mechanical processes on reservoir management. The study field ‘K' belongs to Plio-Pleistocene sequence of deep-water environment with hydrocarbon prospects. This belongs to Post-Rift tectonic stage of evolution with hydrocarbon occurring in structurally controlled traps. As a part of exploration activity, four offset oil wells were drilled earlier which were considered for the geomechanical model construction. Field (K) development plan comprising of six hydrocarbon producers and four water injectors was prepared. Considering the thick water column (300m-650m) in this deep water area of offshore and young unconsolidated sedimentary sequence in the sub-surface, expected pore-pressures can be high whereas the fracture gradient can be low. As a result, the safe drilling mud window can be narrow. Upon successful drilling of a well in such challenging environment without NPT (Non-Productive time), completing the well with best possible technologies suitable to the reservoir's mechanical behavior is utmost important for maximizing the production and minimizing the risk. To mitigate these problems in developing this field, an integrated reservoir geomechanics approach is adopted to optimize the drilling plan and reservoir completion parameters for the planned well. This paper covers the geomechanical study of four wells namely W, X, Y & Z drilled in the field ‘K'. The principal constituents of the geomechanical model are in-situ stresses, pore pressure and the rock mechanical properties. Geomechanical model for the field ‘K' was built utilizing the available data by integrating drilling, geology, petrophysics and reservoir data. Methodology adopted in this paper also highlights how a reliable geomechanical model can be built for a field, which is having data constraints. Constraining of stress magnitudes, orientation and anisotropy added value for efficient well planning in deep waters reservoirs. Calculating well specific reservoir rock mechanical properties, it made possible to identify the most optimal completion strategy. Approach contributed knowledge of geomechanical parameters based on the data of four offset wells has been used for successfully drilling and completion of all the subsequent wells without major challenges. Overall, geomechanical modeling has played a major role in drillability and deliverability of the reservoir. Integrated approach adopted in this paper can be used for well planning and drilling of future wells in East Coast of India with similar geological set up.