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Abstract A method is presented to identify intervals in shale oil reservoirs that contain moveable hydrocarbons with a novel geochemical productivity index, Igp. This index merges 3 important rock properties that always have to be considered for sound shale oil reservoir characterization: vitrinite reflectance (%R°), oil saturation index (OSI), and free water porosity (ϕFW). Integration of this index with other petrophysical properties and geomechanical parameters leads to define intervals with moveable oil. Shale oil is both source and reservoir rock. Hence, it is critical to know both its organic matter maturity and oil/water flow capacity. The introduced Igp considers these features simultaneously; maturity is evaluated by discretizing %Ro from 0 to 1 depending whether the rock is immature or not; free oil flow capacity is modeled normalizing OSI between 0 and 1 based on results from Rock-Eval pyrolysis (REP) obtained in the laboratory or electric logs; and water flow capacity is estimated from ϕFW, obtained with the use of NMR log, which is transformed to an index between 0 and 1. Use of the Igp is explained with real data from a vertical well that penetrates several stacked shale oil reservoirs. However, the same approach can be used in any other kind of wellbore architecture (deviated, horizontal, geosteered). Initially, a correlation between vertical depth and %R° is developed. This results in a continuous organic matter maturity curve along the well section. Next, OSI is simulated with the use of a bin porosity from NMR log, where T2 is between 33 and 80 ms and is correlated with OSI data from REP. As a result, a good match between simulated and real OSI data is achieved. Similar to OSI, ϕFW is also calculated from the NMR log but using a bin porosity when T2 is greater than 80 ms. All these 3 parameters are transformed to partial indexes, which are combined into a unique index, Igp. When the index is greater than 0.66 there is a good chance that the 3 conditions mentioned above will be met. For the example well considered in this study, it was found that almost 30% of total vertical section has good moveable oil potential. This corresponds to 10 intervals in the well. The key novelty of the paper is that it develops a continuous curve of an index that is easy-to-use and is powerful for identifying intervals with moveable hydrocarbon potential. This is true even in those intervals without laboratory data due to the continuity of the Igp curve. In addition, the Igp integrates criteria that are usually applied independently.
This paper develops a new conceptual liquid-hydrocarbons migration model for practical application in organic-rich mudstone reservoirs. The method uses a combination of well log formation evaluation data, micro-resistivity image logs, nuclear magnetic resonance, and geochemical measurements obtained from either drill-cuttings or core data.
In the method proposed in this paper, organic matter (OM) geochemical indicators from organic petrography (thin sections), vitrinite reflectance, TOC from Leco analyzer, Rock-Eval pyrolysis including S1, S2, and Tmax are integrated with triple-combo and NMR logs so that both lean and organic-rich intervals can be identified. The addition of natural fracture intensity to the interpretation package makes the methodology quite unique. After applying cut-offs for each individual parameter, two types of migrations are identified that could take place in these source-rock reservoirs: primary and secondary migration.
The model is applied in a wildcat vertical well that penetrated several stacked organic-rich mudstones. The formation gross thickness of the evaluated section is around of 2800 ft-TVD divided into six main formations composed mainly by siliciclastic minerals with a moderate carbonate content, and low presence of clay minerals. The source-rock reservoirs penetrated by the well can be sub-divided into (1) naturally-fractured, (2) tight and (3) hybrid reservoirs. Reservoirs in sub-division (1) are very important because they might be able to produce oil without the need of hydraulic fracturing. Reservoirs in sub-division (2) have natural fractures but their scale is very small to allow any oil production. Consequently, they must always be hydraulically fractured. Reservoirs in sub-division (3) might or might not need hydraulic fracturing.
Intervals with high organic carbon content, S1, oil saturation index, and geochemical index but low natural fracture intensity indicate tight reservoirs, and they likely correspond to the hydrocarbon source that charged the juxtaposed naturally fractured or hybrid reservoirs. On the other hand, several intervals that present poor TOC, are highly brittle and naturally-fractured, and are connected with tight organic-rich intervals. Thus, the potential of these naturally fractured intervals to produce oil is quite significant.
The novelty of the method developed in this paper permits analyzing primary and secondary migration in the source rock. The method further permits identifying the type of reservoir (naturally fractured, tight and/or hybrid) penetrated by the exploratory wells. This allows ranking the most prospective intervals as well as optimum landing zones for future horizontal or geosteered wells to be drilled in neighboring areas.
Abstract Identification of potential oil flow zones in shale reservoirs has been conducted in the past with the use of an oil saturation index (OSI) determined from Rock-Eval pyrolysis measurements on samples collected at pre-specified depths (partial sampling). This study introduces a new equation that allow continuous OSI determination with the use of the Nuclear Magnetic Resonance (NMR) log. Geochemical analysis using measurements from Rock-Eval pyrolysis and LECO Carbon Analyzer laboratory techniques were carried out in a shale oil reservoir for estimating parameters such as total organic carbon (TOC) and OSI. This allowed identification of hydrocarbons zones. Next, Cross-over and OSI cut-off techniques were applied to distinguish intervals with producible and non-producible hydrocarbons. Subsequently, NMR total response relaxation time, T2, was divided into eight T2 cut-offs to calculate bin porosities. A sensitivity analysis for T2 cut-offs was run in order to establish a good match between the bin porosity and OSI values that indicate producible hydrocarbons. A good agreement was reached among OSI greater than 100 mg HC/gTOC and the bin porosities estimated between T2 = 33ms and 80 ms. This match was corroborated by the visual "oil cross-over" from geochemical analysis. An OSI cut-off equal to 100 mg HC/g TOC has been recommended in the past by several authors to differentiate producible from non-producible oil intervals. That cutoff compares well with the NMR bin porosity developed in this paper. Thus, the porosity estimation between above T2 cut-offs is a good indicator of producible hydrocarbons in a shale oil reservoir. This observation has led to the development of a new equation in this paper to convert the NMR bin porosity to OSI (or vice versa) continuously throughout the NMR logged interval. Also, if TOC is already known from a given method (for example, Passey, Smocker, GR spectral, Uranium), the S1 parameter can be estimated from only well logs resulting in continuous S1 and OSI curves. This is a very significant advantage since Rock-Eval pyrolysis and LECO analyzer are run on samples which are taken at predefined depths (partial sampling); therefore, possible producible oil zones could be bypassed if only core results are taking into account.
Abstract The geochemical and petrophysical complexity of source-reservoirs in Liquid-Rich Unconventional plays (LRU) urges for the implementation of alternative analytical protocols for initial play assessment. In this study, samples from selected source-reservoirs in the USA and the UK were analyzed by high frequency-nuclear magnetic resonance (HF-NMR relaxometry), followed by hydrous pyrolysis, and modified Rock-Eval pyrolysis methods (multi-heating rate methods, MHR). The analytical protocol here presented attempts to better qualify and quantify different petroleum fractions (mobile, heavy hydrocarbons, viscous, solid bitumen), and thus provide valuable and refined information about producibility of target intervals during appraisal stages. Modified Rock-Eval Pyrolysis (MHR). Briefly, the pyrolysis oven program had four temperature ramps (at 50 °C/min) and isothermal plateaus (maintained isothermal for 15 minutes) at 200°C, 250°C, 300°C and 350°C, with a fifth and last ramp of 25°C/minute to 650°C. HF-NMR Relaxometry Hydrogen NMR measurements were made with a special 22MHz spectrometer from MR Cores equipped with a 30-mm diameter probe. The T2 data were acquired using the CPMG sequence with an echo time spacing of TE=0.07 ms. The T1 data were acquired using an inversion-recovery sequence. Selected samples (Kimmeridge Clay, Green River Shale) were subjected to hydrous pyrolysis experiments. Crushed rock chips (2-4 g, 1-3mm top size) were loaded into mini-reactor vessels (25-35 mL internal volumes). Rock chips were covered with deionized water and the reactor was placed in a gas chromatograph oven at the chosen temperature, generally for 72h. Initial results show how the hydrocarbon fractions interpreted from NMR regions are in good agreement with those from MHR pyrolysis analysis in terms of hydrocarbon mobility/producibility. Results from hydrous pyrolysis experiments show that an exception to this general agreement between NMR and MHR estimates occurs for the Kimmeridge Clay samples, where MHR shows an increase of > 90% in producible hydrocarbon yields vs. minimal to no presence of mobile hydrocarbons in NMR T1-T2 maps. Ongoing experiments will clarify the role of pore structure and networks in these discrepancies of producible oil estimates when comparing pyrolysis with NMR-based techniques. This multi-step, multidisciplinary approach provides an opportunity to use it as a screening analysis to identify zones of higher OIP and predict fluids mobility prior to drilling. The novelty of our study is the integration of laboratory-derived analytical data (HF H-NMR, MHR and Hydrous Pyrolysis, organic petrography) to assess the proportion of the OIP that is producible prior to drilling or completions.
Abstract This paper develops innovative methods for analysis of some important exploration and production problems in shale petroleum reservoirs such as the determination of burial maturity and maturation trajectories, and determination of sweet spots with the use of Modified Pickett plots. The methods are explained with data from 226 Niobrara wells. Pickett plots have been used historically as a powerful tool for petrophysical analysis of well logs. The plots represent a snapshot on time that corresponds to the time when the well logs are run. Pickett plots rely on pattern recognition observable on log-log crossplots of porosity vs. true resistivity. The analysis has been used in the past primarily for determination of water saturation. However, the plot has been extended throughout the years for evaluation of other parameters of practical importance including, for example, permeability, process or delivery speed (permeability over porosity, k/ϕ), bulk volume of water (BVW) and pore throat apertures. In this paper, Pickett plots are extended from representing a snapshot on time to representing millions of years of burial and maturation trajectories. The proposed method is explained with data from 226 Niobrara wells. The modified Pickett plots leads to curved lines of water saturation (Sw) and BVW. The maturation trajectories on the plot help to explain compaction and why as maturation increases to generate oil and gas condensate, resistivity goes up. However, as maturation increases to generate dry gas in the Niobrara, resistivity decreases. The Lopatin time-temperature index (TTI) is also included in the modified Pickett plot. The proposed methodology also allows estimating changes in pore throat sizes updip and downdip of a structure, as well as in a basin flank. The ability to combine maturity, pore throat sizes, as well as porosity and process speed in a single graph makes the modified picket plot a valuable tool with potential to locate sweet spots in shale petroleum reservoirs to locate areas for possible improved oil recovery (IOR) and enhanced oil recovery (EOR). The key contributions of this paper are generating an original method for determining burial maturity and maturation trajectories of shale petroleum reservoirs with the use of modified Pickett plots, as well as determining changes in pore throat sizes in different places of a structure, which lead to the location of sweet spots. Although the methodology is explained with data of the Niobrara shales, it should have application in other shale petroleum reservoirs of the world.