This paper attempts to answer a fundamental question pertinent to fracture characterization of unconventional basement reserves using rock mechanics & petrophysics; are open fractures in basements necessary critically stressed? Evaluation of naturally occurring fractures are critical for production as well as reserves estimation. In this regard, a study well was drilled in the basement section of the Cauvery basin to explore unconventional pay zones & characterize the contributing fractures by integrated Geomechanical & Petrophysical analysis.
A suite of open hole logs including the basic, acoustic and electrical borehole images were acquired and an integrated approach was taken, including geomechanical analysis to identify the contributing fractures. Standard petrophysical evaluation in basements was inconclusive and porosity quantification from fractures posed a major challenge. Image log analysis involved identification of conductive and resistive fractures in the gauged wellbore and combining Stoneley reflectivity further indicated probable open fractures. Following this, a geomechanical analysis was carried out to determine the current in-situ stress orientation/magnitudes based on observed breakouts. Finally a CSF study was done to check for fracture slip events.
Based on the integrated study of Petrophysics and Geomechanics, an optimized workflow was developed and the critically stressed fractures were identified. It was found that, while some fractures strike direction was different from the present day maximum horizontal stress direction (SHmax), in general, most fractures were indeed aligned to SHmax. To check the fluid flowing capability of fracture networks, formation tester was deployed in selective zones for testing and sampling. Successful hydrocarbon sampling from selective fractures with orientation not aligned to SHmax led to the validation of the current study. The results proved that while most critically stressed/open fractures did indeed contribute to flow, a smaller fraction of the naturally occurring fractures while contributing to flow, were not necessarily aligned to the in situ orientations.
The results present a discrepancy between observation and the expectation that open fractures are necessarily oriented parallel or nearly parallel to modern-day SHmax. This works highlights the fact that although paleo-stresses may influence the fracture networks, it is the contemporary in-situ stresses that truly dominate fluid flow and only through a detailed understanding of the critically stressed areas, can we come to a decisive conclusion that further improves overall recovery.
This seminar will teach participants how to identify, evaluate, and quantify risk and uncertainty in everyday oil and gas economic situations. It reviews the development of pragmatic tools, methods, and understandings for professionals that are applicable to companies of all sizes. The seminar also briefly reviews statistics, the relationship between risk and return, and hedging and future markets. Strategic thinking and planning are key elements in an organisation’s journey to maximise value to shareholders, customers, and employees. Through this workshop, attendees will go through the different processes involved in strategic planning including the elements of organisational SWOT, business scenario and options development, elaboration of strategic options and communication to stakeholders.
A hydrocarbon find has always been an exploration geologist’s adventure and has remained at the forefront of the E&P cycle for the survival of the oil and gas industry. Big and easy finds are a distant past; therefore, the quest has shifted to go beyond conventional sandstones and carbonates to more complex areas of unconventionals: low porosity, low permeability, low resistivity, tight and ultra-tight, HPHT, shale, CBM, gas hydrates, and any other possible regime including deeper, geologically complex, and seismically opaque features such as salt, basalt, sub-basalt, even basement.
Decisions in E&P ventures are affected by Bias, Blindness, and Illusions (BBI) which permeate our analyses, interpretations and decisions. This one-day course examines the influence of these cognitive pitfalls and presents techniques that can be used to mitigate their impact. Bias refers to errors in thinking whereby interpretations and judgments are drawn in an illogical fashion. Blindness is the condition where we fail to see an unexpected event in plain sight. Illusions refer to misleading beliefs based on a false impression of reality.
Digital core generated from micro CT images of rock sample cutting and results obtained from digital core analysis are presented in this work as a substitute of conventional core study for Petrophysical evaluation. Conventional core extraction during drilling, core preservation and analysis are expensive, time consuming processes and often unavailable for small size fields. Moreover, routine and special core analysis results are a critical input for petrophysical characterization. In this situation, digital core study appears to be a cost effective substitute to ensure and validate petrophysical evaluation results.
High resolution 3D micro CT imaging and analysis was done on rock samples cut during drilling or on sidewall core plugs cut by wireline logging tool. Segmented micro CT image slices when combined in 3D space in three orthogonal directions, can be termed as digital core. Solid rock matrix, clay filled and porous rock portions are distinctly separable using micro CT images and their volume fractions can be estimated. Detail textural analysis in terms of Grain and pore throat size distribution of the rock is possible from digital core which controls storage capacity and flow behavior. Two critical petrophysical input parameters for fluid saturation (Sw) estimation are cementation exponent (m) and saturation exponent (n). These parameters are commonly computed from special core analysis (SCAL) on conventional core plugs. But digital core study can provide the estimates of ‘m’ and ‘n’ which replace the need of SCAL.
Digital core study has been carried out in three different reservoirs in west and east coast of India and the results were analyzed. Porosity and permeability data obtained from digital core was first compared with log analysis results and then used to identify different petro physical rock types (PRT). Fluid saturation (Sw) was estimated from resistivity log by using ‘m’ and ‘n’ exponent obtained from digital core seems to be more realistic and corroborates with well test results. Porosity, permeability, water saturation and rock types (PRT) were helped to build geo-cellular model (GCM) for small and marginal reservoir.
Enhanced reservoir characterization by using digital core study result has helped in better understanding and decision making for small and marginal fields where limited well data is available. Finally this leads to the preparation of field development plan (FDP). Digital core technique is less expensive, having quick turnaround time than conventional coring which has translated into high value business impact for any development project.
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.
The Natural Gas Hydrate Program Expedition (NGHP) has been formed to explore and develop the gas hydrate resources of Indian subcontinent in three stages. The first stage was to identify the presence of gas hydrate deposits in Indian Offshore Basins and the second stage was to identify gas hydrate in sand rich geological setting within gas hydrate stability zone and suitable locations for production testing. During the second stage, 42 gas hydrate wells at 25 sites were completed in deep water areas of Krishna Godavari and Mahanadi offshore in Eastern Coast of India.
This paper provides an insight into formation evaluation techniques as effective tools of evaluating gas hydrate saturation. During the second stage of the expedition; LWD, wireline well log data and pressure cores were acquired and they have been used for estimation and validation of gas hydrate saturations. The gas hydrate saturation have been estimated by three methods viz., standard deterministic Archie method, probabilistic method using ELANPlus model and Density Magnetic Resonance (DMR) technique. This paper also emphasizes the estimation of gas hydrate saturation considering gas hydrate as a part of matrix in the ELANPlus model and validation with pressure core results.
In Petrophysical model, hydrate can be considered either as a pore-filling hydrocarbon (fluid) or as a matrix mineral (rock constituent). When it is assigned as a pore-filling hydrocarbon, the model calculates the matrix volumes & porosity and calculates the water saturation in the same way as the basic interpretation model. When the hydrate is considered as a constituent of the matrix in the model, hydrate volume is calculated and the hydrate saturation is then arrived at by dividing this volume by the total porosity.
Hydrate is invisible to Nuclear Magnetic Resonance (NMR) measurements. In DMR technique, the deficit in NMR porosity as compared to Density porosity is used to estimate the hydrate volume accurately.
Gas hydrate saturation estimation in one of the well drilled during the second stage of the expedition from Krishna Godavari basin is discussed in detail in this paper. Gas hydrate saturation estimated from DMR method is found to be close agreement with other methods such as deterministic Archie and ELANPlus based probabilistic methods. The gas hydrate saturation is found to be in the range of 20-60% in the considered well. The results have been validated with gas hydrate saturation obtained from pressure cores retrieved from the nearby core hole.
The present approach is to estimate gas hydrate saturation with different methods and validation with pressure core data to minimize uncertainty in estimation of petrophysical parameters for such type of unconventional reservoirs.
Saha, Sankhajit (Baker Hughes, a GE company) | Gariya, Bhuwan Chandra (Hindustan Oil Exploration Company Ltd) | Panda, Debabrata (Hindustan Oil Exploration Company Ltd) | Perumalla, Satya (Baker Hughes, a GE company) | Podder, Tuhin (Baker Hughes, a GE company) | Thanvi, Shrikant (Baker Hughes, a GE company) | Deshpande, Chandrashekhar (Baker Hughes, a GE company)
Drilling through the thick shale sequence (Oligocene to Paleocene age) of Cauvery offshore showed severe wellbore instability in the past due to incompatible mud program that increased overall operational cost. While new high-angle sidetrack development wells had been planned, three major challenges need to be addressed. First, proper mud weight recommendation for preventing mechanical instability; second, introduction of a cost-effective mud system preventing time-sensitive failure; and finally, mitigating the environmental impact factor of the mud system.
Geomechanical modelling and Hole Stability analysis had been performed based on available dataset. An optimized mud weight (MW) program was developed based on the analysis. Considering the time-dependent failure characteristics of the shale and overall cost effectiveness, just modifying the mud weight does not address all of the challenges delineated above. Consequently, special "high-performance water-based mud system (HPWBM)" was designed instead of oil-based mud (OBM). This HPWBM was formulated based on the nature of shales encountered. While drilling, real-time geomechanics further facilitated controlled drilling conditions and optimized the mud program.
The well-based geomechanical model indicated a hydrostatic pore pressure gradient in the region. The relative magnitude of three principle stresses showed a normal fault stress regime and maximum horizontal stress (SHmax) azimuth appeared to be nearly aligned to the N-S direction. Hole Stability analysis showed that a minimum of 12 ppg mud weight was required to drill the 8½" section. The sidetrack holes had a maximum inclination of 75 to 77 degrees. Different polymers and bridging agents were added to prepare the customized HPWBM in order to address shale instability and formation damage due to overbalance. Real-time monitoring during drilling operation utilized logging while drilling (LWD) log data, drilling parameters and mud logging data to promote smooth drilling operations. Through systematic planning and execution, the high-angle sidetrack holes had been drilled with zero non-productive time (NPT) in terms of well bore stability. More than 50% cost reduction was achieved on the mud system.
An integrated solution that includes pre-drill geomechanics, HPWBM system design and real-time well monitoring helped to reduce the risks due to model uncertainties while drilling high angle wells through the thick shale section. This approach helped to reduce significant operational cost with an improved success rate.
Chakraborty, Srimanta (Baker Hughes, a GE Company) | Panchakarla, Anjana (Baker Hughes, a GE Company) | Deshpande, Chandrashekhar (Baker Hughes, a GE Company) | Malik, Sonia (Baker Hughes, a GE Company) | Singh Majithia, Pritpal (ONGC) | Chaudhary, Sunil (ONGC) | Murthy, AVR (ONGC)
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.
Mechanical failure of cap rock is one of the main reasons of CO2 leakage from the storage formations. Through comprehensive assessment on the petrophysical and geomechanical heterogeneities of cap rock, it is possible to estimate the pressure distribution more accurately and to predict the risk of unexpected caprock failure. To describe the fracture reactivation and fracture permeability, modified Barton-Bandis model and dual permeability system are applied. Porosity-permeability relationship is calculated with power law. In order to generate hydro-geomechanically heterogeneous fields, the negative correlation between porosity and Young's modulus/Poisson's ratio is applied. In comparison to homogeneous model, effects of heterogeneity are examined in terms of vertical deformation and the amount of leaked CO2. To compare the effects of heterogeneity, heterogeneous models for both geomechanical and petrophysical properties in coupled simulation are designed.
Simulation results show that CO2 leakage occurs after 4-6 years from injection. After 10 year injection with petrophysically heterogeneous and geomechanically homogeneous caprock, CO2 leakage is larger than that of homogeneous model. In contrast, heterogeneity of geomechanical properties is shown to mitigate additional escape of CO2. Vertical displacement of every heterogeneous model is larger than homogeneous model. According to results from model with petrophysically heterogeneous and geomechanically homogeneous caprock, the higher Dykstra-Parsons coefficients (