Predicting the properties of reservoirs beyond the wellbore has been the cornerstone of reservoir characterization. The outcome provides the framework for efficient management and optimization of hydrocarbon reservoirs. Proper reservoir characterization affects all reservoir types and all stages during the life of a field. Far-field characterization encompasses seismic, electromagnetic, and other geophysical surveys. This characterization can be facilitated in various configurations such as cross-well or surface-to-wellbore, accomplished while drilling, in open and cased wells, and while producing hydrocarbons.
This paper presents a multidomain integrated workflow that combines geophysics, borehole geology, fracture modeling, and petroleum systems analysis for characterization and resource assessment of basement plays. A 3D fracture model is developed by integrating image log interpretation and seismic data to assess the reservoir potential of fractured basement. The 3D fracture modeling is done using the discrete fracture network (DFN) approach with image log interpretation and other fracture drivers serving as the main input. The DFN is upscaled to generate fracture porosity and fracture permeability properties in a 3D grid. The upscaled fracture porosity is used to estimate the petroleum initially in place (PIIP) for the prospects. Multiple 2D petroleum system modeling is performed where large fault throws are identified from seismic interpretation. The petroleum system study helps in identification of areas with most prolific hydrocarbon generation and expulsion centers, which, coupled with the cross-fault juxtapositions, are the main locales of charging for basement reservoir. Further analysis of all the elements of basement play (i.e., source, reservoir, seal, trap, and migration) is done, and prospective areas within the basement play are delineated with high geological chance of success.
Saluja, Vikas (Oil & Natural Gas Corporation LTD.) | Singh, Uday (Oil & Natural Gas Corporation LTD.) | Ghosh, Aninda (Oil & Natural Gas Corporation LTD.) | Prakash, Puja (Oil & Natural Gas Corporation LTD.) | Kumar, Ravendra (Oil & Natural Gas Corporation LTD.) | Verma, Rajeev (Oil & Natural Gas Corporation LTD.)
The case study demonstrated here is the innovative workflow for fault delineation technique on a 3D seismic volume in B-173A Field of Heera Panna Bassein (HPB) Sector, Western Offshore Basin, India. B-173A is located 50 kms west of Mumbai at an average water depth of about 50 m. The field was discovered in the year 1992 and it was put on production in Aug 1998. In B-173A field there are two hydrocarbon bearing zones one is gas bearing Mukta (Lower Oligocene carbonates) Formation and oil bearing Bassein (Middle to Upper Eocene Carbonates) formation.
The present study is an extended workflow on Advanced Seismic Interpretation using Spectral Decomposition and RGB Blending for Fault delineation. Iso-frequency volumes are extracted from Relative Acoustic Impedance data instead of seismic data itself.
The workflow is for effective fault delineation and it consists of Spectral Decomposition of relative acoustic impedance data and RGB Blending of discontinuity attributes of different Iso-frequency volumes.
It is observed that RGB blend volume of discontinuity attributes provided more convincing results for fault delineation as compared to the results of traditional discontinuity attributes.
Identification of a prospect is normally done based on seismic interpretation and geological understanding of the area. However, due to the inherent uncertainties of the data we still observe in many cases that all key petroleum system elements are present, but still the drilled prospect is dry. Such failures are mostly attributed to a lack of understanding of seal capacity, reservoir heterogeneity, source rock presence and maturation, hydrocarbon migration, and relative timing of these processes. The workflow described in this paper aims to improve discovery success rates by deploying a more rigorous and structured approach. It is guided by the play-based exploration risk assessment process. The starting point is always that the process is guided by the the basic understanding of a mature kitchen should always be based on a regional scale petroleum systems model. However, while evaluating prospects, the migration and entrapment component of a prospect should always be investigated by means of a locally refined grid-based petroleum system model. The uniquepart of this approach is the construction of a high-resolution static model covering the prospects, which is built by using available well data, seismo-geological trends and attributes to capture reservoir potential. Additional inputs such as fault seal analysis also helps to understand prospect scale migration and associated geological risks. In the regional play and local prospect-scale petroleum system models, geological and geophysical inputs are utilized to create the uncertainty distribution for each input parameter which is required for assessing the success case volume of identified prospects. The evaluated risk is combined with the volumetric uncertainty in a probabilistic way to derive the risked volumetrics. It is further translated into an economic evaluation of the prospect by integrating inputs like estimated production profiles, appropriate fiscal models, HC price decks, etc. This enables the economic viability of the prospects to be assessed, resulting in a portfolio with proper ranking to build a decision-tree leading to execution and operations in ensuing drilling campaigns.
PY-1 is one of the few fields in India producing hydrocarbons from Fractured Basement Reservoir. The field was developed with nine slot unmanned platform with gas exported through a 56 km 4" multiphase pipeline to landfall point at Pillaperumalnallur. Field was put on production in November 2009 with three extended reach wells. The production performance of the field had some surprise and declined earlier than expected. As a result, based on the conclusions drawn from an integrated subsurface study, a two wells reentry campaign to side track wells Mercury and Earth was planned to be executed in Q1 2018. The objectives of this paper are twofold: 1. Review the production performance of a granitic basement gas field and share learnings which may be useful for similar fields being developed elsewhere.
Biswal, Debakanta (Adani Welspun Exploration Limited) | Nedeer, Nasimudeen (Adani Welspun Exploration Limited) | Banerjee, Subrata (Adani Welspun Exploration Limited) | Singh, Kumar Hemant (Indian Institute of Technology)
The boundary between a thick carbonate layer and its substrata is often a well-defined reflector due to the presence of shaly and clayey layers beneath the carbonates. This reflector and other underlying reflectors result in a velocity pull-up effect because the seismic velocities within the carbonates are higher than that of the surrounding sediments. The geometry of velocity pull-up beneath the carbonate body is related to the geometry of the structure and the thickness of the carbonate body the seismic wave travels through.
In B9 area of Mumbai Offshore basin, the reservoir facies are largely represented by clastics deposited along tidal deltaic lobes. Wells drilled though Daman formation have encountered good quality pay sands within the Daman formation. This pay has produced commercial quantities of hydrocarbons in the vicinity making the area attractive for further exploration and exploitation. The overlying Bombay formation consists mainly of shale with occasional bands of limestone and claystone. The development of thick isolated carbonates bodies within Bombay formation is observed in "C" structure on which "Well-C" is placed. This is seen to significantly constrain the structural configuration in the "C" area. There is a possibility of substantial extension of the "C" structure towards south if the impact of velocity pull up due to carbonate build up can be successfully mitigated. The ultimate challenge is to image the Daman reservoirs, mitigating overburden lateral velocity variations.
In addition to a layered cake depth conversion approach for depth conversion of the time map, a more robust approach, PSDM followed by depth conversion was carried out. This paper highlights the merit of different methods.
Until recently, reservoir characterization methods in the industry were limited to use of seismic technologies in exploration of oil and gas and had a very constrained role in production and development. In the past, using characterization for development fields was considered a very perilous task. Technological advancements and the risk-averse mindset have significantly expanded the application of reservoir characterization. Today, reservoir characterization is the basis of any development plans made for a commercial field.
Development of 3D reservoir modeling techniques to generate field development plans (FDPs) marked a step-change in reservoir characterization methods. Introduction of geostatistics and numerical simulation made it possible to build precise models to generate realistic field development scenarios. This is the state-of-the-art seismic-to-simulation method of reservoir characterization used in FDPs today. However, the struggle to estimate reservoir properties spatially away from the well continues.
Surface seismic data provide excellent areal coverage but do not provide the vertical resolution required for a fine-scale reservoir model. Geostatistical methods reduce the uncertainty in spatial distribution of petrophysical properties from pseudo-point supports (wells) but are not calibrated spatially between the wells. Correspondingly, the fluid saturation distribution and the parameters used in dynamically calculating the same during numerical simulation are not calibrated in the interwell space.
This paper details necessary data acquisitions and methods of calibration of 3D reservoir model to reduce uncertainty in the interwell space. The data acquisition methods have been available for some time, but have rarely been electronically incorporated in the 3D reservoir model and have been largely used to analytically guide the modeling and its inferences. A logical way of interpreting the results of acquisitions and calibrating the 3D reservoir model cell-by-cell is detailed in this paper.
Seismic attributes play an important role during reservoir characterization and three-dimensional (3D) lithofacies modeling by providing indirect insight of the subsurface. Using seismic attributes for such studies has always been challenging because it is difficult to determine a realistic relationship between hard data points (i.e., well information) and a 3D volume of seismic attributes. However, a probability-based approach for 3D seismic attribute calibration with well data provides better results of lithofacies modeling and spatial distribution of reservoir properties. This paper presents a probability-based seismic attribute calibration technique that has been described for 3D lithofacies modeling and distribution. This approach helps in subsurface reservoir characterization and provides a realistic lithofacies distribution model. This approach also helps reduce uncertainty of lithofacies prediction compared to conventional methods of simply using geostatistical algorithms.
Bennett, Nicholas (Schlumberger-Doll Research) | Donald, Adam (Schlumberger) | Ghadiry, Sherif (Schlumberger) | Nassar, Mohamed (Schlumberger) | Kumar, Rajeev (Schlumberger Middle East S.A.) | Biswas, Reetam (The University of Texas)
A new sonic-imaging technique uses azimuthal receivers to determine individual reflector locations and attributes, such as the dip and azimuth of formation layer boundaries, fractures, and faults. From the filtered waveform measurements, an automated time pick and event-localization procedure is used to collect possible reflected arrival events. An automated ray-tracing and 3D slowness time coherence (STC) procedure is used to determine the raypath type of the arrival event and the reflector azimuth. The angle of incidence of the reflected arrival is related to the relative dip, and the moveout in 3D across the individual sensors is related to the azimuthal orientation of the reflector. This information is then used to produce a 3D structural map of the reflector, which can be readily used for further geomodeling.
This new technique addresses several shortcomings in the current state-of-the-art sonic-imaging services within the industry. Similar to seismic processing, the current sonic-imaging workflow consists of iteratively testing migration parameters to obtain a 2D image representing a plane in line with the desired receiver array. The image is then interpreted for features, which is often subjective in nature and does not directly provide quantitative results for the discrete reflections. The technique presented here, besides providing appropriate parameter values for the migration workflow, further complements the migration image by providing dip and azimuth for each event that can be used in further downstream boundary or discontinuity characterization.
A field example from the Middle East is presented in which a carbonate reservoir was examined using this technique and subsequently integrated with wellbore images to provide insight to the structural geological setting, which was lacking seismic data due to surface constraints. Structural dips were picked in the lower zone of the main hole and used to update the orientation of stratigraphic formation tops along the well trajectory. 3D surfaces were then created and projected from the main hole to the sidetrack to check for structural conformity. One of the projected surfaces from the main hole matched the expected depth of the formation top in the sidetrack but two were offset due to the possible presence of a fault. This was confirmed by parallel evaluation of the azimuthal sonic-imaging data acquired in the main hole that showed an abrupt change in the relative dip of reflectors above and below the possible fault plane using the 3D STC and ray tracing. Dip patterns from both wells showed a drag effect around the offset formation tops, further confirming the presence of a fault. A comparison of the acquired borehole images pinpointed the depth and orientation of the fault cutting both wells to explain the depth offset of the projected 3D formation top surfaces.
An XFEM-EDFM scheme and associated monolithic solution method are proposed to model time-dependent poromechanics and two-phase flow. Fractures are modeled as interfaces with displacement discontinuities. The contact forces are treated using Lagrange Multipliers. A number of numerical tests are performed to investigate the Newmark scheme's accuracy and cases for wave propagation in poroelastic and natural fracture media are implemented to evaluate computational efficiency. We apply the method to model seismic data from hydraulic fracture network. Empirical results validate the Newmark scheme accuracy as well as computational efficiency and localization of newton update in seismic field is necessary for the further application. The synthetic model of multiple hydraulic stages illustrates the effect of flow coupling and newly generated fractures on the microseismic field. The model is applied to simultaneously assimilate well performance and microseismic observations, thereby informing about the causal event dynamics.