Anirban Banerjee

Bio: Anirban Banerjee is an academic researcher from Baker Hughes. The author has contributed to research in topics: Reservoir modeling & Neutron. The author has an hindex of 2, co-authored 4 publications receiving 6 citations.

Impact of dynamic slippage on productivity of shale reservoirs

Abstract: Ultra low permeability rocks such as shales exhibit complex fracture networks which must be discretely characterized in our reservoir models to evaluate stimulation designs and completion strategies properly. The pressure (Darcy’s law) and composition driven (Fick’s law) flow mechanisms when combined result in composition, pressure and saturationdependent slippage factor. The approach used in this study is to utilize pressure-dependent transmissibility multipliers to incorporate apparent gas-permeability changes resulting from multi-mechanism flows in commercial simulators. This work further expounds on the effectiveness of the theory by presenting a descriptive analysis between two commercially utilized numerical simulators. The applicability of dynamic slippage as an effective flow mechanism governing gas flow mechanisms within the computational environment of two different simulators is attempted in this analysis. Results indicate that slippage-governed flow in modelling shale reservoirs should not be ignored.

Application of Pulsed Neutron Logging in Open Hole Environment

Abstract: The identification of fluid saturations in depleted reservoir sands is critical to understand the reservoir potential and field life. However, in case of water flooding, the formation water salinity of the reservoirs sands might be altered and fluid saturations from conventional petrophysical analysis can be misleading. This will have direct impact on the field economics. A salinity independent saturation computation from Carbon/Oxygen (C/O) log becomes a necessity in such development wells– a first of such application in a field under secondary recovery for this basin. C/O well logging has been extensively used in cased hole environments to determine saturation behind casing. They are used essentially to determine oil saturation in cased hole conditions for depleted reservoirs. While their cased hole applications have been well established; for the study well, a pulsed neutron tool was used in an open hole environment to determine the fluid saturations to compare against the saturations computed from conventional resistivity logs. This study helped in the determination of fluid saturations in mixed salinity reservoir sands, which were to be explored from subsequent wells in the field. The hydrocarbon-bearing sands in the field were water injected in nearby wells to enhance recovery. Development wells drilled in the field relied on petrophysical evaluation from conventional open hole data and pressure testing and fluid sampling depths were determined accordingly. A pulsed neutron tool was deployed in an open hole well after operational constraints were encountered with the formation testing tool. As an alternative, the pulsed neutron data were acquired in the well to compute salinity independent water saturation based on C/O log response as against the fluid saturation computation from resistivity logs. The determination of fluid saturations from C/O helped in determination of altered salinity for the sand intervals in the field. For the study well, C/O-derived water saturation was found to be higher than that from resistivity log computation. This was significant in identification of water breakthrough in the bottom interval of the reservoir sands. This paper details the method and findings of C/O logging in open hole environment from Western Onland Basin in India. The critical solutions provided for the reservoir sands in the field and enabled the operator to save significant well cost and rig time by making informed decision of not lowering the casing in this well section.

Integrated Approach of Reservoir Characterization Using Multi-Component Induction Tool in Thinly Laminated Pay Sands- A Case Study from Eastern Offshore India

Abstract: A number of exploratory wells were drilled in Eastern Offshore of India, encountering thick turbiditic sequences. The formation evaluation through conventional logging tools is a challenge in such depositional environments as the tools are unable to resolve thin beds and provides a weighted average log response over a collection of beds. In such environments, often the potential pay intervals are overlooked if comprehensive petrophysical analysis is not carried out. While the thin bed problem underestimates the reservoir potential, the orientation of measurement of the petrophysical properties further complicates the problem due to formation anisotropy. Another important characteristic of layered thin bed sand shale sequence is the acoustic anisotropy due to the transversely isotropic nature of sedimentary deposition. The multicomponent induction tool was logged in the study area, providing a tensor measurement of the horizontal (Rh) and vertical (Rv) components of resistivity. The well encountered thick turbidite sequence of laminated pay sands with very low resistivity contrast. The initial stochastic petrophysical analysis from conventional open hole log responses indicated poor reservoir quality with high water saturation. Integration of high-resolution acoustic data and VTI analysis with multicomponent induction tool shows a clear evidence of alternating shale and sand sequences in the target reservoir. A high-resolution processed acoustic porosity was incorporated to build the lithology model with multicomponent resistivity data. Integration of ResH, ResV and VTI into a Thomas-Stieber petrophysical model indicates potential hydrocarbon bearing sands at two depths which were further included to optimise the formation testing and sampling plan. During fluid sampling at the two identified depths, 54 and 157 ltrs. of fluid volume was pumped out before collecting samples by utilizing real time downhole fluid identification technologies. Optical absorbance and refractive indices were used to differentiate between miscible fluids. Clean-up from SOBM to formation oil was monitored using trends in representative channels of constantly changing absorbance spectrum. The formation testing results, therefore, were in good agreement with the identified pay intervals from the T-S model. Furthermore, Stoneley permeability analysis were carried out in the study area and calibrated with formation testing results. In the absence of imager data in the example well, formation dip was computed based on the multicomponent induction tool, which provided a close match to the OBM imagers, which struggled due to low formation resistivity, logged in adjacent wells. This paper highlights the integrated workflow of multicomponent resistivity data based Thomas Stieber petrophysical model with high resolution acoustic and formation tester results of the example well and its success in delineation of pay sand intervals.

Geomechanical Sanding Analysis: Criticality in Testing and Sampling in Unconsolidated Formations - A Case History

Abstract: Sand production in unconsolidated formations during sampling can lead to poor quality of samples being acquired due to plugging of flow lines and sealing issues at the probe. Formation pressure and mobility measurements can also be affected by sand production which may cause plugging inside the tool or at the tool inlet and result in increased operational time. Predicting sanding potential thus becomes critical to achieve both operational and formation characterization objectives, especially in deep-water environments, where operation costs are high. Calculating "Critical Draw Down" (CDD) pressure and predicting the sanding envelope through geomechanical-sanding analysis provide insights critical to successful testing and sampling operation. A fit for purpose geomechanical model has been developed based on petrophysical data along with regional knowledge of geomechanical conditions. With the geomechanical model, analytical sanding evaluation is used to calculate a range of CDD values for the likely testing and sampling points using well logs from offset wells. Logs from the studied well are analyzed in real time to update CDDs. The zones least prone to sand production are identified and prioritized for testing and sampling. The pre-drill sanding risk assessment is also used to optimize operational parameters including selection of the best pump and packer types while the real time updated CDD values is incorporated to limit the flowing (drawdown) pressures during the sampling and testing operations. A case study from a deep-water field in India is highlighted where the mentioned workflow developed post logging for a pilot wellbore has helped to optimize decisions in real time during formation pressure testing and sampling in its sidetrack wellbore, thus adding value to reservoir characterization objectives and reducing nonproductive time (NPT). Based on the pre-drill sanding assessment, CDD was found to be in the range of 0 - 500 psi below the formation pore pressure in some of the sand bodies. Also, a large face packer was recommended to enhance sealing efficiency by increasing the contact area with the formation. Pump rate was regulated during pressure testing and sampling to ensure that the pressure never exceeded the pre-defined CDD values thus preventing sand production. Multiple fluid samples were collected successfully without any plugging. This integration of geomechanical assessment with operation contributed to 32% increase in success rate for good quality pressure testing and acquisition of representative samples in the sidetrack wellbore, benefitted from a systematic adaptation of pre-job assessment and real time optimizations compared to the pilot wellbore. The pre-drill petrophysical and geomechanical evaluations provide critical insights to assist in real time optimization of pressure testing and fluid sampling operations in unconsolidated reservoirs. Workflow presented in this paper has proven to be valuable in obtaining reliable formation pressure data and contamination-free formation fluid samples for accurate reservoir and fluid characterization in unconsolidated formations during wireline logging testing and sampling operations.

Laboratory characterization of crude oil and sandstone reservoir for chemical enhanced oil recovery

Abstract: Purpose Because of the increasing global oil demand, efforts have been made to further extract oil using chemical enhanced oil recovery (CEOR) methods. However, unlike water flooding, understanding the physicochemical properties of crude oil and its sandstone reservoir makeup is the first step before embarking to CEOR projects. These properties play major roles in the area of EOR technologies and are important for the development of reliable chemical flooding agents; also, they are key parameters used to evaluate the economic and technical feasibilities of production and refining processes in the oil industries. Consequently, this paper aims to investigate various important physicochemical properties of crude oil (specific gravity; American Petroleum Institute [API]; viscosity; pour point; basic sediment and water; wax; and saturate, aromatic, resins and asphaltenes components) and sandstone reservoir makeup (porosity, permeability, bulk volume and density, grain volume and density, morphology and mineral composition and distributions) obtained from Malaysian oil field (MOF) for oil recovery prediction and design of promising chemical flooding agents. Design/methodology/approach Three reservoir sandstones from different depths (CORE 1; 5601, CORE 2; 6173 and CORE 3; 6182 ft) as well as its crude oil were obtained from the MOF, and various characterization instruments, such as high temperature gas chromatography and column chromatography for crude’s fractions identification; GC-simulated distillation for boiling point distribution; POROPERM for porosity and permeability; CT-Scan and scanning electron microscopy-energy dispersive X-ray for morphology and mineral distribution; wax instrument (wax content); pour point analyser (pour point); and visco-rheometre (viscosity), were used for the characterizations. Findings Experimental data gathered from this study show that the field contains low viscous (0.0018-0.014 Pa.s) sweet and light-typed crude because of low sulfur content (0.03 per cent), API gravity (43.1o), high proportion of volatile components (51.78 per cent) and insignificant traces of heavy components (0.02 per cent). Similarly, the rock permeability trend with depth was found in the order of CORE 1 < CORE 2 < CORE 3, and other parameters such as pore volume (Vp), bulk volume (Vb) and grain volume (Vg) also decrease in general. For grain density, the variation is small and insignificant, but for bulk density, CORE 2 records lower than CORE 3 by more than 1 per cent. In the mineral composition analysis, the CORE 2 contains the highest identified mineral content, with the exception of quarts where it was higher in the CORE 3. Thus, a good flow crude characteristic, permeability trend and the net mineral concentrations identified in this reservoir would not affect the economic viability of the CEOR method and predicts the validation of the MOF as a potential field that could respond to CEOR method successfully. Originality/value This paper is the first of its kind to combine the two important oil field properties to scientifically predict the evaluation of an oil field (MOF) as a step forward toward development of novel chemical flooding agents for application in EOR. Hence, information obtained from this paper would help in the development of reliable chemical flooding agents and designing of EOR methods.