Capillary pressure is a crucial step in reservoir properties definition and distribution during static and dynamic modelling. It is a key input into saturation height modelling (SHM) process, understanding the fluid distribution and into reservoir rock typing process. Capillary pressure models provide an insight into field dynamic for the identification of swept zones and provide another calibration besides the log calculated saturation. Capillary pressure curve tends to be more complex in carbonates in comparison to sandstone reservoirs because of post deposition processes that impact the rock flow properties, hence complex pore throat size distribution (uni-modal, bi-modal or tri-modal). Therefore, accurate determination of this property is the cornerstone in the reservoir characterization process.
Capillary pressure can be obtained using several experimental techniques, such as mercury injection (MICP), centrifuge (CF) and porous plate (PP). Each method has its own inherited advantages and disadvantages. The MICP method tends to be faster, cheaper and provides a full spectrum of pore throat size of a plug. Whereas, the PP method can be carried out at reservoir conditions with minimum required corrections.
In this paper, a detailed workflow for quality control capillary pressure is discussed. The workflow is sub-divided into three main parts: Instrumental and experimental level, core measurement level and logs level. Experimental level starts with proper designing the actual procedure of the capillary pressure experiment. Parameters such as pore volume, bulk volume and grain density are investigated at core measurement level. In geological-petrography montage, all petrography data; X-Ray Diffraction (XRD), Scanning Electron Microscope (SEM), thin section and computed tomography scan (CT) are used along with the capillary pressure curve for assessment. Comparing various methodologies of experimental technique carried out on twin plugs, if exist, are also investigated. The capillary pressure that passes the previous QC steps is used as input into saturation-point comparison as a logs level QC. The saturation calculated from capillary pressure is compared to log-derived water saturation eliminating any issues with porosity and permeability of the trims and provides insight to the uncertainty level in the model. As an additional step, the MICP measurements are fitted with bi-modal Gaussian basis functions with two practical benefits. First, the quality of this fitting is a useful indicator for the evaluation of pore structure complexity and the identification erroneous measurements. Second, the fitting parameters are useful inputs for geological interpretation, rock typing and SHM. This rapid and automated workflow is a useful tool for screening, processing and integration of large-scale capillary pressure data sets, a key step in integrated reservoir description, characterization and modelling.
Unconventional tight reservoir sands have low porosity and very low permeability (mostly less than 0.1mD) due to their fine grain size and poor grain sorting that is often exacerbated by extensive diagenetic effects such as cementation and compaction. Petrophysical evaluation in these formations is very challenging. Conventional downhole logs such as density, neutron, sonic, gamma ray and resistivity measurements provide limited information on pore size variations and often missed Key geological features especially at the early stages of reservoir development. Fluid characterization at the earliest possible stage is paramount to guide the development of these reservoirs where tight well spacing, stimulation (fracturing) and or horizontal well completion is usually required. The main objective of this paper is to show a process of fluid characterization in unconventional tight sand that guides reservoir stimulation.
Porosity partitioning using nuclear magnetic resonance (NMR) logging data helps address these challenges in three distinct steps. First, the 1-dimensional (1D) NMR T2 spectrum quantifies the amount of bound and free fluids pore space and reveals reservoir quality with unique sensitivity. In this step, the NMR fluid substitution method was utilized to ensure consistency between NMR logs in oil-based mud (OBM) and water-based mud (WBM) systems. Second, the free fluids are further subdivided into hydrocarbon and water phases using a 2-dimensional (2D) NMR T1/T2 processing technique. Third, the hydrocarbon phase is subdivided again into liquid and gas phases where a gas flag is turned on whenever the NMR gas signal significantly exceeds measurement uncertainty. This enables detection of live hydrocarbons with high gas-oil ratio (GOR).
This paper presents the integration of NMR analysis into petrophysical evaluation of an unconventional tight sand reservoir. The evaluation helped optimize the best interval for stimulation. Fluid sample acquired with formation tester correlated very well with NMR log-based fluid prediction.
Integrated NMR analysis, including bound fluid vs. free fluid analysis and 2D NMR-based fluid characterization, including gas indicator flag, was applied to establish the presence and type of hydrocarbon in tight sands and select the best representative interval for stimulation. The continuous reservoir quality and fluid distribution profiles provided by these logs were beneficial for the geological understanding and complex formation testing operations in this challenging reservoir.
Formation evaluation studies suggest that high in the hydrocarbon column, the resistivity logs can precisely quantify fluid saturation due to the large contrast in the resistivities of hydrocarbon-bearing and water-bearing formations. However, in the transition zone where water and oil reside in more or less equal volumes, the determination of hydrocarbon saturation by resistivity value becomes challenging. Some of these intervals exhibit low resistivity pay (LRP) characteristics where resistivity-based log analysis predicts high water saturation, yet they can produce little or no water-cut.
Conventional log-based saturation and rock quality evaluation in a low permeability carbonate reservoir is difficult due to the lack of the input measurement's sensitivity to pore size and the amount of pore-filling fluids. Pore size information provided by Nuclear Magnetic Resonance (NMR) logs from this LRP provides good sensitivity, but it needs to be calibrated for quantitative use. The objective of this study is to determine a height-based NMR Bulk Volume Irreducible (HBVI) cutoff to distinguish and quantify the amounts of reservoir fluids across a wellbore using NMR logs.
The procedure consists of two-part workflow. The first part describes the acquisition of a data base that includes high-quality laboratory NMR and capillary pressure measurements to determine the pore aspect ratio and the effect of temperature on the formation's NMR properties using core samples from the target reservoir. These measurements are then used to underpin the mathematical description of the HBVI cutoff as a function of displacement pressure that is translated to height above the free water level (HAFWL). The second part of the workflow is a well-log processing scheme where the new formula is implemented to calculate a continuous fluid saturation profile across the well using NMR logs.
The laboratory measurements suggest a good agreement between the capillary pressure and NMR T2 measurements. Both data sets indicate a well sorted pore size distribution. The T2 relaxation time increases with temperature, which is then considered in the downhole implementation of the HBVI model. The NMR-based saturation log is consistent with wireline formation testing (WFT) observations and mercury injection capillary pressure (MICP)-based saturation height modeling results in a low resistivity pay reservoir.
The results of this study suggest that the laboratory calibration and NMR log processing workflows described herein provide a viable alternative for the calculation of fluid saturations in complex reservoirs where the conventional log-based saturation evaluation faces uncertainties.
Due to the shallow depth of investigation of logging tools such as Nuclear Magnetic Resonance (NMR), the signal interpretation of the flushed zone must be performed carefully. Understanding invasion effects on the logs is an important prerequisite for any petrophysical evaluation. While it is relatively easier to evaluate and correct for the effect of filtrate invasion in basic logs, such as triple combo, special care must be taken for advanced logging techniques such as NMR. For example, it is generally assumed that the volume of remaining wetting fluid in the flushed zone equals to the volume of micropores that do not contribute to flow when the well is produced. The amount of these immobile fluids is estimated using the NMR bound fluid log, a key input for the prediction of rock quality and well performance, especially in complex clastic and carbonate pore systems. In certain formations, NMR bound fluid logs exhibit some differences between adjacent wells drilled with oil-based (OBM) and water-based muds (WBM). This paper summarizes the lessons learnt from a laboratory NMR study of oil-based mud filtrate (OBMF) invasion as a function of rock mineralogy and microstructure, mud chemistry and displacement/flow pressure.
In this work, we studied the effect of a commercial surfactant usually added in OBM formulations. We investigated the effect of different surfactant concentrations on the fluid-fluid interfacial tension (IFT) properties and on the fluid-solid interaction properties, using contact angle measurements on both sandstone and carbonate model surfaces. Furthermore, we investigated the effect of the additive on the capillary pressure properties and remaining water saturations on sandstone and carbonate rocks. To maximize the generality of the results we used two very different driving mechanisms for the fluid displacement: centrifuge and flow-through.
The data showed that carbonate and clastic rocks behaved differently over a wide range of flow mechanisms and water saturations, proving that mineralogy plays a crucial role in the fluid displacement. Under the measurement uncertainties, the irreducible water saturation, however, remained constant regardless of the OBMF composition or driving mechanism.
We showed how sandstone and carbonate rocks behave in respect to wettability alteration due to a surfactant used in OBM formulations. The systematic difference, whatever the driving mechanism is, strongly suggests that the differences in NMR responses between sandstone and carbonate originate from chemical composition and surface properties rather than microstructural differences between sandstone and carbonate rocks.
We provide experimental findings proving that the NMR T1/T2 ratio of the oil phase in a mixed-saturated rock strongly correlates with wettability. NMR laboratory data acquired using refined oil (Soltrol) demonstrate a linearly decreasing trend between the T1/T2 ratio of the oil phase and the rock wettability measured by the USBM technique. For downhole applications, the main challenge is to separate the NMR signals of oil and water. To address this challenge, a two-step workflow is used. First, the NMR signal is separated into those from the oil phase and water phase using 2D diffusivity vs. T2 analysis where the overall T2 distributions of oil and water are determined. These distributions guide the subdivision of individual slices of a 3D D-T2-T1/T2 cube into water and oil areas and the calculation of their partial pore volumes. The T1/ T2 ratio for each fluid is calculated as an average T1/T2 weighted by its partial porosity at each T1/T2 slice. This T1/ T2 ratio is converted to rock wettability by the laboratory correlation. We also discuss data acquisition limitations and potential improvements of the workflow.
Wettability is one of a few critical reservoir properties that is fundamental to reservoir description and engineering, as exemplified by Morrow (1990). There are many established laboratory wettability testing methods (Amott, 1959; Donaldson et al., 1969; Ma et al., 1999) but each one has its inherent advantages and disadvantages. The biggest concern for any laboratory wettability test is that people are not sure how representative the testing samples are to the targeted reservoir, even with great effort in core preservation or wettability restoration (Ma and Amabeoku, 2014).
It was proposed that reservoir wettability may be characterized downhole using measurements, such as reservoir pressure profiling with a formation tester (Desbrandes and Gualdron, 1988). Its application has been rare, possibly due to the difficulties to reduce the noise around in-situ capillary pressure measurement caused by pressure gauges, mud properties, the extent of filtrate invasion, and all other issues related to pretest pressure measurements (Proett et al., 2015).
This paper presents a new methodology for performing a cutoff analysis that uses a T1/T2 ratio distribution obtained from two-dimensional (2D) nuclear magnetic resonance (NMR) T1 and T2 measurements. The ability to classify pores and their effect on permeability is noticeably improved compared to a T2-based approach, of which T2 cutoff values vary from a few tens of milliseconds to a few seconds. Based on mercury injection capillary pressure results, the T1/T2 ratio-based cutoff is used to differentiate porosity with a pore throat radius larger than 2 µm from smaller pore throats. The T1/T2 cutoff ranges narrowed to within 1.4 to 1.7 for 100% water-saturated carbonate cores. In addition, the empirical models of NMR-based permeability are enhanced by incorporating the porosity, T1/T2 ratio cutoff, and T2 geometric mean. For the studied data set of 49 carbonate rock samples with a permeability range spanning six orders of magnitude, an excellent correlation coefficient of R2 = 0.9 was observed between the NMR predicted permeability and that measured in the laboratory. This improved permeability prediction technique has the potential to be implemented in applications of downhole NMR logging.
Formate-based drilling mud is used to improve the performance of drilling and completions of high pressure and high temperature (HPHT) wells due to its properties such as high density (up to 19 lbs/gal), non-corrosiveness, eco-friendliness, high stability, and miscibility with brine and other fluids in the drilling muds. However, these strengths of formate muds pose challenges for formation evaluation due to their unusual properties such as high density, low Hydrogen Index (HI), miscibility with connate brines, and high conductivity.
The current work addresses challenges of Nuclear Magnetic Resonance (NMR) logging, which is known to provide capillary bound fluid for producibility evaluation and accurate porosity for reserve estimation, in deep dry gas wells drilled with formate mud. With a carefully designed workflow composed of a suit of laboratory NMR techniques, the needs for the correction of T2cutoff and HI by Formate Mud Filtrate (FMF) invasion have been investigated. To quantify the accurate amount of correction required, FMF invasion has been monitored under reservoir conditions. The experimentally determined NMR T2 cutoff values for FMF saturated samples are always slightly longer than those for brine saturated ones. The difference of bulk volume movable (BVM), however, is less than 5% when T2 cutoff value from brine saturated sample is applied to FMF saturated sample. Thus, T2 cutoff determined by conventional NMR laboratory measurement with brine can be applied to NMR log with the formation invaded by FMF.
The HI correction factors for BVM and bulk volume irreducible (BVI) are dependent on pore structures. For brine saturated bi-modal sandstones, all pores are displaced by FMF which corresponds to an HI correction factor of 0.74 for both BVM and BVI. For brine saturated carbonate with tri-modal pore system, however, 100% BVM and 70% of BVI have been displaced with FMF which correspond to HI correction factor of 0.78 and 0.80 for the FMF used in the current study, respectively.
The outcome of the current study will help to enhance the usage of NMR logging as powerful formation evaluation tool for gas wells drilled with formate based drilling muds.
Timely and detailed evaluation of in-situ hydrocarbon flow properties such as oil density and viscosity is critical for successful development of heavy oil reservoirs. The prediction of fluid properties requires comprehensive integration of advanced downhole measurements such as nuclear magnetic resonance (NMR) logging, formation pressure, and mobility measurements, as well as fluid sampling.
The reservoir rock presented in this paper is an unconsolidated Miocene formation comprising complex lithologies including clastics and carbonates. The reservoir fluids are hydrocarbons with significant spatial variations in viscosity ranging from (60-300 cP) to fully solid (tar). Well testing and downhole fluid sampling in this formation are hindered by low oil mobility, unconsolidated formation that generates sand production, emulsion generation, and very low formation pressure.
We present a two-pronged log evaluation workflow to identify sweet spots and to predict fluid properties within the zones of interest. First, the presence of "missing NMR porosity" and "excess bound fluid" is estimated by comparing the NMR total and bound fluid porosity with the conventional total porosity and uninvaded water-filled porosity logs, respectively. Secondly, two-dimensional NMR diffusivity vs. T2 NMR analysis is performed in prospective zones where lighter and, possibly, producible hydrocarbons are detected. The separation of oil and water signals provides a resistivity-independent estimation of the shallow water saturation. Additionally, we correlated the position of the NMR oil signal with oil-sample viscosity values. The readily available log-based viscosity greatly improves the efficiency of the formation and well-testing job.
We successfully sampled high viscosity hydrocarbon fluids by utilizing either oval pad or straddle packer. The customized tool designed for sampling aided gravitational segregation of clean hydrocarbons from the water-based mud filtrate and emulsion; and therefore providing representative reservoir fluid samples based on downhole fluid analyzers.
Several light oil and gas reservoirs are present within an extensive Permian clastic sequence in the Middle East. Well logs and core data revealed numerous challenges for the petrophysical description of this formation. Rapidly changing depositional environments and diagenetic effects caused heterogeneities in grain size and sorting within clean sands. Consequently, gamma ray and conventional porosity logs have little sensitivity to rock quality variations. Secondly, an influx of meteoric water into the reservoir rocks decreased formation water salinities which adds uncertainties to the estimation of fluid saturations from resistivity logs. Finally, gas-oil contacts are present in some reservoirs where log-based in-situ hydrocarbon typing is of great practical value. The introduction of nuclear magnetic resonance (NMR) logs has successfully mitigated these issues as evidenced by petrophysical interpretations and formation testing in the area's exploration and delineation wells.
Lateral facies variations and complicated reservoir structures warranted the deployment of NMR technology in horizontal development wells for better well placement and completion optimization with logging while drilling (LWD) NMR as the most preferable option. The NMR logs led geosteering decisions and proactive well planning to singificantly increase reservoir contacts in producer wells. Permeability predicted by the NMR logs is of great value in real-time well placement decisions and completion design including ICD installations. The low-gradient LWD NMR measurement gives rise to a very simple and robust real-time fluid identification thanks to the the good separation of water and oil signals in the NMR T2 spectrum. This fluid quantification, combined with bound fluid analysis, helps determine the well's position in the transition zone by detecting free water.
This paper summarizes the experience with both wireline and LWD NMR technologies in the area. Lessons learned include considerations for deployment, tool activations and NMR interpretation.
This publication presents the calibration of a downhole nuclear magnetic resonance (NMR) log-based oil viscosity correlation with laboratory live oil viscosity measurements. The laboratory data set was acquired from formation tester sampling (FTS) including 37 pressurized single-phase oil samples taken from 11 wells. The FTS oil viscosity range was 1-1,400 centiPoise (cP).
In two Saudi Arabian carbonate fields, the moveable hydrocarbons consists of crude with in-situ oil viscosities of ~1-3 cP. Thick tar mats are located below the oil columns, separating the moveable hydrocarbons from the aquifers. For pressure support, horizontal water injectors are drilled into the heavy oil transition zones, located between the moveable oil and the tar, utilizing real-time logging while drilling (LWD) NMR data and formation tester mobility data for well placement. For optimum water injector placement, accurate NMR log-based determination of the reservoir oil viscosity is critical. The NMR logs are processed using an integrated petrophysical model that subdivides the oil volume into light, medium and heavy components. The in-situ viscosities are calibrated to the relative percentage of heavy-medium components to the total oil volume.
Despite the large geographic distance between the 11 sampled wells, the presented results reveal a remarkable consistency between the in-situ oil viscosity data from the FTS laboratory analyses and the NMR log responses. In this particular case, the well results suggest that one viscosity relationship is adequate for describing a large geographical area containing multiple medium and heavy oil reservoirs. The results indicate the logarithm of viscosity to be a clear function of the heavy-medium oil volume percentage. Two distinct linear segments are sufficient to cover the full 1-1,400 cP oil viscosity range. One of these segment describes the mobile oil column with low heavy-medium oil volume percentage and oil sample viscosity of less than 3 cP. The other segment defines the oil/tar transition zone where the presence of asphaltene aggregate structures leads to a very rapid increase of oil viscosity versus depth covering the range 3-1,400 cP. The robustness of the method is demonstrated by the low statistical uncertainties for the entire viscosity range, when comparing the predicted NMR oil viscosity correlation results with the laboratory results, from the 37 physical oil samples.
The new NMR empirical oil viscosity correlation was built on a previously published methodology, but the existing correlation did not do a particularly good job for the lower oil viscosity range (<10 cP) and for the very heavy oils. The purpose of this new publication is to present a new empirical NMR viscosity correlation with much wider validity range.