The appraisal phase is a unique opportunity to evaluate reservoir continuity for reducing key uncertainties required for field development decisions and planning. Consequently, appraisal activities for large offshore reservoirs necessitate optimal fluid and formation data acquisition and analysis to reduce reservoir uncertainties. This is critical for assessment of vertical and lateral reservoir connectivity, flow assurance or fluid production behaviors under future EOR schemes. Reservoir Fluid Geodynamics (RFG) studies incorporating downhole fluid analysis (DFA) measurements and analysis of reservoir fluid samples help establish origin and history of the fluids in the reservoir - from charge through to present day (4.2 km apart Mullins, 2019). This new discipline coupled with geochemical, image and core analysis allows addressing important risk factors, such as vertical and lateral reservoir connectivity. This paper shows how DFA gradient analysis and implications regarding charge, geology evolution from log data and whole core, and well test evaluation all combine to give a robust interpretation of the good news of excellent lateral connectivity. The Upper Miocene age Zama oil discovery, located in the offshore Sureste Basin of Mexico, was initially identified as a three-way dip structure sealed against a normal fault system. It consists of individual stacked turbiditic sands as seen on borehole images and logs, overlain by a thick hemipelagic shale. During field appraisal, formation testing data and representative fluid samples were required for assessing reservoir connectivity and for input to engineering studies. The initial appraisal wells could not be sampled effectively using established sampling technologies since many reservoir intervals were poorly consolidated. A new formation testing platform was deployed in two appraisal wells to overcome these challenges. This new system enabled focused sampling and downhole fluid analysis, with collection of pure samples while maintaining controlled low-pressure drawdowns during sample cleanup. In real-time, downhole fluid analysis measurements were used to guide the sampling process, identify additional depth intervals requiring characterization, and enable assessment of reservoir continuity between different flow units using RFG principles. More than thirty pressure-compensated fluid samples of high-quality and purity were efficiently collected at multiple depths. Subsequent laboratory analysis of the sampled fluids confirmed the favorable case of laterally extensive connectivity of the stacked sands sequences. Petroleum geochemistry analysis also corroborated measurements of reservoir fluid gradient and asphaltene concentration gradients; which provided further insights on timing of migration and reservoir charging. Interpretation of geological image logs and subsequent full core analysis were consistent with DFA gradient analysis, and the lateral connectivity predictions were confirmed during a multi zone well test. This case study demonstrates how RFG analysis using advanced formation testing and sampling measurements integrated with borehole image and petrophysical log evaluations enables reservoir connectivity assessment and predictions for a large field offshore Mexico.

Core measurements are often employed to detect rock types for improved well-log-based petrophysical evaluation and subsequent formation evaluation in noncored wells. However, acquisition of such measurements can be time-consuming, delaying rock classification efforts for weeks or months after core retrieval. On the other hand, well-log-based rock classification cannot provide high-resolution detection of rock types in heterogeneous and anisotropic formations. Interpretation of 2D computed tomography (CT) scan data has been identified as an attractive and high-resolution option for enhancing rock texture detection, classification, and formation evaluation. Acquisition of CT-scan data is accomplished shortly after core retrieval, providing high-resolution data for immediate use in petrophysical workflows. However, these 2D images cannot capture 3D variation of rock texture, which can cause uncertainty in detection of rock classes. The objectives of this paper include (a) to derive rock fabric related features from whole-core 3D CT-scan image stacks and slabbed whole-core photos using image analysis techniques, (b) to integrate image-based rock- fabric-related features with conventional well logs and routine core analysis for fast and accurate detection of petrophysical rock classes, and (c) to employ the detected petrophysical rock classes for improved formation evaluation. First, we conducted conventional well-log-based formation evaluation to obtain petrophysical and compositional properties of the evaluated formations. Then, we developed a new workflow for pre-processing of whole-core 3D CT-scan image stacks and slabbed whole-core photos, and subsequent image-based rockfabric- related features extraction. Then, we employed the image-based rock-fabric-related features for detection of image-base rock classes. Finally, the detected petrophysical rock classes and flow units were employed for improved formation evaluation and permeability estimates. We successfully applied the proposed workflow to a data set from a siliciclastic sequence with rapid spatial variations in rock fabric and pore structure. The use of whole-core 3D CT-scan image-stacks-based rock-fabricrelated features accurately captured changes in the rock properties within the evaluated depth interval. Imagebased rock classes derived by integration of whole-core 3D CT-scan image-stacks-based and slabbed whole-core photos-based rock-fabric-related features were in agreement with expert-derived lithofacies. Furthermore, use of the image-based rock classes in formation evaluation of the evaluated depth intervals improved estimates of petrophysical properties such as permeability compared to conventional formation-based porosity-permeability estimates. A unique contribution of the proposed workflow compared to the previously documented rock classification methods is the derivation of quantitative features from whole-core 3D CT-scan image-stacks, which are conventionally employed qualitatively. Furthermore, image-based base rock-fabric related features extracted from whole-core 3D CT-scan image stacks can be employed as tool for quick assessment of recovered whole-core, for tasks such as core-plug location and revealing depth intervals showing abnormal characteristics.

Downhole Fluid Analysis (DFA) is one pillar of Reservoir Fluid Geodynamics (RFG). DFA measurements at varying depths and multiple wells provide both vertical and lateral fluid gradient data. These gradients, especially the asphaltene gradient derived from accurate optical density (OD) measurements, are critical in thermodynamic analysis to assess the degree of equilibration and identify RFG processes. Recently, an RFG study was conducted using both DFA and laboratory data from seven wells in an oilfield in the Norwegian North Sea. Fluid OD gradients show that most of the reservoir has equilibrated asphaltenes with a lateral variation of 20%. This indicates connectivity in the large portion of the reservoir, which is confirmed by three years of production data from the field. There are two outliers off the asphaltene equilibrium curve implying isolated sections: one is located on the extreme east flank of the field and the other on the extreme west flank. The asphaltene fraction varies by a factor of six between these two sections. Such difference reveals that different charge fluids entered the reservoir, and the equilibrated asphaltenes are the result of an after-charge mixing process. In addition, although GOR and fluid composition demonstrate apparent equilibration, different gas-oil contacts (GOCs) exist in the reservoir indicating a lateral solution gas gradient. Geochemistry analysis shows same level of mild biodegradation in all the fluid samples, including those from the two isolated sections. This leads to the conclusion that biodegraded oil spills into the whole reservoir with little or no in-reservoir biodegradation. Furthermore, lateral asphaltene gradients at different times after charge have been preserved, the initial lateral gradient after charge is measured to be a factor of 6 in asphaltene content and, in present day, is now 20%. This unique dataset provides a valuable opportunity to constrain a simulation of reservoir fluid mixing processes after charge to present day. The purpose of the simulation is to investigate the factors which impact the evolution of lateral composition gradients in geologic time in a connected reservoir. Numerical simulations were performed over geologic time in 2D isothermal reservoir models filled by oil with a lateral density gradient. This density gradient imitates the lateral compositional gradient in GOR and asphaltenes measured in the North Sea field. Simulations show that this lateral gradient creates lateral differential pressures and causes a countercurrent fluid flow forming a convection cell. However, in reservoirs with realistic vertical to horizontal aspect ratios, such fluid flows are not rapid, and some degree of lateral gradients can be retained in moderate geologic times. Additionally, diffusion was included in the simulation of the mixing process. The reservoir model was initialized with two different GOCs producing subtle lateral GOR and density gradients. Simulated mixing process transports gas from regions of higher GOR to regions of lower GOR and reduces the difference between the GOCs. However the flux of solution gas transport is very small. Consequently, we conclude that lateral GOR and asphaltene gradients can persist for moderate geologic time, which is consistent with the observation from the field.

A new logging while drilling (LWD) acoustic tool has been developed with novel ultrasonic pitch-catch and pulse-echo technologies. The tool enables both highresolution slowness and reflectivity images, which cannot be addressed with conventional acoustic logging. Measuring formation elastic-wave properties in complex, finely layered, formations is routinely attempted with sonic tools that measure slowness over a receiver array with a length of 2 ft or more depending upon the tool design. These apertures lead to processing results with similar vertical resolutions, obscuring the true slowness of any layering occurring at a finer scale. If any of these layers present significantly different elastic-wave properties than the surrounding rock, then they can play a major role in both wellbore stability and hydraulic fracturing but can be absent from geomechanical models built on routine sonic measurements. Conventional sonic tools operate from approximately 0.1 kHz to 20 kHz and can deliver slowness information with approximately 1 ft or more depth of investigation. This is sufficient to investigate the far field slowness values but makes it very challenging to evaluate the nearwellbore region where tectonic stress redistribution causes pronounced azimuthal slowness variation. This stress-induced slowness variation is important because it is also a key driver of wellbore geomechanics. Moreover, in the presence of highly laminated formations there can be a significant azimuthal variation of slowness due to layering that is often beyond the resolution of conventional sonic tools due to their operating frequency. Finally, in horizontal wells, multiple layer slownesses are being measured simultaneously because of the depth of investigation of conventional sonic tools. This can cause significant interpretational challenges. To address these challenges, an entirely new design approach was needed. The novel pitch-catch technology operates over a wide frequency range centered at 250 kHz and contains an array of receivers having a 2 in. receiver aperture. The use of dual ultrasonic technology allows the measurement of high-resolution slowness data azimuthally as well as reflectivity and caliper images. The new LWD tool was run in both vertical and horizontal wells and directly compared with both wireline sonic and imaging tools. The inch-scale slownesses obtained show characteristic features that clearly correlate to the formation lithology and structure indicated by the images. These features are completely absent from the conventional sonic data due to its comparatively lower vertical resolution. Slowness images from the tool reflect the formation elastic-wave properties at fine scale and show dips and lithological variations that are complimentary to the data from the pulse-echo images. The physics of the measurement are discussed along with its ability to measure near wellbore slowness, elastic-wave properties and stress variations. Additionally, the effect of the stress-induced nearwellbore features seen in the slowness images and the pulse-echo images is discussed with the wireline dipole shear anisotropy processing

Performing high-resolution electrofacies analysis greatly contributed to the understanding of the connectivity and to the volume estimation of the recently discovered deep-water Calumbi Formation play of Sergipe Basin, Northeast of Brazil. It is considered the most important discovery in the country after the Pre-salt carbonate reservoirs and consists of turbiditic channel and lobe complexes of Campanian-Maastrichtian age. In the present study, unsupervised classification based on the Multi-Resolution Graph-Based Clustering (MRGC) method was used to the electrofacies analysis. Available rock data were initially classified into lithofacies according to Mutti facies. For the interpretation of the electrofacies, a reclassification was made based on the lithofacies described in the Bouma sequence, resulting in 5 clusters correlated to conglomerate and sandstone to interlaminated and shale slump facies. The quality control was performed for all available logs and the petrophysical core data were incorporated into the analysis for rock data depth calibration. After log processing and validation, the correlation between core and well-log data was performed. Textural facies were extracted from resistivity image logs through the generation of self-organizing maps (SOM), which worked as the input that would guarantee the high resolution of the electrofacies analysis. The use of SOM with MRGC method presented excellent results, with a good correlation between the electrofacies and the rock data and showing a good resolution as required to better understand the reservoirs of the Sergipe Basin. INTRODUCTION Northeast of Brazil has the most important discovery of the country after the Pre-salt carbonate reservoirs. It is a play of Calumbi Formation in the deep waters of the Sergipe Basin. The first well of this area was drilled in 2010. After six years of exploratory campaign the new oil province had more than 20 wells drilled, in water depths of almost 3,000 m and well final depths sometimes greater than 6,000 m. The discoveries constitute accumulations with significant heights of hydrocarbons, and the drilling campaign represents an exploratory success rate of over 70%.

ABSTRACT Exploring for a wide range of hydrocarbon reservoirs, including carbonate systems is increasingly important in times of higher resource demand and progressively dwindling reserves. Exploration for carbonate systems is generally more difficult than siliciclastic reservoir exploration because of intrinsic heterogeneities, which occur at all scales of observation and measurement. Heterogeneity in carbonates can be attributed to variable lithology, chemistry/mineralogy, pore types, pore connectivity, and sedimentary facies. These intrinsic complexities can be related to geological processes controlling carbonate production and deposition, and to changes during their subsequent diagenesis. The term "heterogeneity" is rarely defined and almost never numerically quantified in petrophysical analysis, although it is widely stated that carbonate heterogeneities are poorly understood. This work in carbonates of the Tal block has investigated how heterogeneity can be defined and how we can quantify this term by describing a range of statistical heterogeneity measures (e.g., Lorenz and Dykstra-Parsons coefficients). These measures can be used to interpret variation in wireline log data, allowing for comparison of their heterogeneities within individual and multiple reservoir units. Through this investigation, the Heterogeneity Log has been developed by applying these techniques to wireline log data, over set intervals of 10, 5, 2 and 1m, through a carbonate reservoir. Application to petrophysical rock characterization shows a strong relationship to underlying geological heterogeneities in carbonate facies, mud content and porosity (primary & secondary porosities) in the Tal block. Zones of heterogeneity identified through the successions show strong correlation to fluid-flow zones. By applying the same statistical measures of heterogeneity to established flow zones it is possible to rank these units in terms of their internal heterogeneity. Both increased and decreased heterogeneity are documented with high reservoir quality in different wireline measurements; this can be related to underlying geological heterogeneities. Heterogeneity Logs can be used as a visual indicator of where to focus sampling strategies to ensure intrinsic variabilities are captured. Carbonate lithology and mineralogy can be highly variable, both vertically and horizontally through a succession. Carbonate depositional environments produce a diverse range of sedimentary facies which contain different porosity types with varying degrees of connectivity, producing complex and irregular pore networks. Minerals such as calcite, aragonite, and dolomite may co-exist within a single rock unit in varying proportions. Carbonate minerals have different stabilities and are susceptible to the many postdepositional processes of diagenesis. Porosity-permeability relationships in carbonate reservoirs are notoriously poorly defined, although work by authors such as Lucia (1995; 2000) suggest correlations can be derived from pore type and grain size relationships. The ability to predict porosity and permeability relationships in carbonates continues to be an area of industry research interest. Reservoir zonation is often established using poroperm features through complex statistical analysis, although traditional placement of flow zone boundaries comes down to visual assessment and an analyst's experience and expectations. This study therefore focuses on developing these techniques and applying them to carbonate petrophysical and geological data including borehole image and cre data in the Tal block, which can have further application to characterizing poroperm relationships, fluid flow zone identification and sampling strategies.

ABSTRACT Determining the potential of shale gas reservoirs involves an exhaustive process of calculating the volume of total gas, or Original Gas In Place (OGIP). The calculation of total gas relies on calibrating wireline logs to core data; which are considered to be an empirical validation or ‘ground truth’. However, inconsistency in sample preparation and analytical techniques within, and between laboratories creates significant uncertainty in calculating the free and adsorbed gas components which constitute total gas. Here we present an analytical program performed on samples of core to elucidate the causes of uncertainty in calculation of total gas. The findings of this program are used to propose improved methods of calculating total gas from core. Free gas calculated from properties such as porosity and water saturation measured on core was found to be highly dependent on laboratory analytical protocols. Differences in sample preparation and water extraction method led to relative differences of 20% in water saturation and 10% in porosity observed between laboratories, leading to differences of 35% in calculations of free gas in place. Adsorbed gas was evaluated using methane adsorption testing to study the changes in Langmuir parameters in samples with a wide variety of water saturations, clay content, and total organic content over a range of temperatures. It was found that the storage capacity of adsorbed gas artificially increased by a factor of two to three when experimental temperature exceeded the boiling point of water. This increase is related to the expulsion of clay bound water and subsequent availability of clay surfaces for methane adsorption. Total gas in place is the sum of free and adsorbed gas volume estimates. The interaction and overlap of pore space between these two volume components are also important to consider. It is proposed to use a simplistic mono layer-based correction of volume of adsorbed gas from the free gas volume based on a composite pore size distribution from scanning electron microscopy (SEM) point counting and nitrogen adsorption data. Pressurized sidewall core samples were acquired at reservoir conditions to measure free and adsorbed gas volumes during controlled depressurization under laboratory conditions. This provided a baseline measurement for comparison with calculations from traditional measurements to understand which laboratory protocol and sample preparation technique provided the most robust results This study has elucidated methods to reduce the uncertainty in gas in place calculation and better understand resource distribution in dry gas source rocks.

ABSTRACT The purpose of this study was to correlate subtle changes in reservoir quality to production. The groundwork was provided by unique lessons arising from core and log analyses, including machine learning, to identify target facies within the reservoir and stage level production logs provided by permanent fiber optic cable. Production results on a stage level produced by fiber optics provided insight into production drivers. These lessons were then applied to fracture and reservoir models. The workflow began by categorizing unique facies within the Eagle Ford shale with the help of a selforganizing map model. Wireline log variables, such as gamma ray, neutron porosity, bulk density, deep resistivity, and compressional slowness, were used to discern different facies within the Eagle Ford shale. These log facies demonstrated an excellent match with whole core-derived facies, which took into account mineral volumetric compositional variation, carbonate grain-size variation, and kerogen content. Before completing the study well, a cased hole logging suite was run, and the facies were identified along the lateral. Permanent fiber optic cable was installed on the backside of the casing to observe completions and production trends along the lateral. Experiments performed throughout the completions included varying rate and perforation design, use of chemical diversion and acid, and pump schedules. Fluid and proppant per lateral foot were held constant throughout the lateral. Calibrated fracture and reservoir models were then built around the observed completion effectiveness and initial production results of each stage. Despite the changes in completion design, the only solid correlation in initial production is the facies identified along the lateral. The best producing facies were those with the highest porosity and organic content. Although a modeled fracture height exceeded 50 ft, the reservoir quality immediately adjacent to the wellbore was the largest determining factor in initial production. The strong correlation between these facies led to further investigation between production mechanisms and reservoir quality. Current trends to improve unconventional completions include increased perforated clusters, pounds of proppant, and gallons of fluid per lateral foot. However, reservoir understanding and quality lateral landing targets cannot solely be replaced by larger completions.

ABSTRACT Severe biodegradation of crude oil is widely known to increase viscosity quite significantly. Water washing is known contribute to this increase under some circumstances. What has been less understood is the spatial variation of viscosity in reservoirs that is caused by biodegradation. Biodegradation-induced gradients are expected because the microbes live in water and consume oil at the oil-water contact (OWC), thus biodegradation is far from uniform in the oil column. Case studies reviewed here show that reservoirs with biodegraded crude oil can have large viscosity gradients at/near the oil-water contact (OWC) or have no variation of viscosity or have variations of viscosity at the top of the oil column. These entirely different outcomes depend on reservoir fluid geodynamic (RFG) processes that occur in conjunction with biodegradation. The combination of downhole fluid analysis and geochemical analysis is shown to delineate the particular RFG processes that control viscosity variations associated with biodegradation. The extent of spill-fill and the evolution of biodegradation is of particular concern. In addition, diffusive mixing can minimize viscosity gradients from biodegradation and depends strongly on overall distance from the OWC, thus depends on tilt angle of the reservoir. In addition, reservoir temperature is important in that biodegradation ceases above 80°C. The different case studies presented herein account for the dominant viscosity profiles associated with biodegradation and provide guidance for optimal reservoir evaluations and inputs to development decisions INTRODUCTION Biodegradation can significantly modify oil properties and increase viscosity which impacts economic potential, well production rates and downstream handling: important considerations for optimal field development planning. In going from no biodegradation to severe biodegradation, microbes can typically consume ∼2/3 of the oil (Head et al, 2003). The microbes consume at most negligible quantities of the asphaltenes; consequently, severe biodegradation can result in a tripling of the asphaltene concentration. The viscosity of crude oil depends essentially exponentially on asphaltene content. In addition, the microbes consume many lower viscosity components of the crude oil such as light alkanes. Even moderate biodegradation can negatively affect crude oil viscosity.

ABSTRACT This paper presents the first while-drilling acquisition of nuclear magnetic resonance (NMR) polarization buildup data in slim boreholes drilled in complex clastic and carbonate reservoirs. NMR logging data is paramount to the petrophysical evaluation of complex rocks such as silty sands, heterogeneous carbonates and reservoirs with variable hydrocarbon viscosity in many fields of the region. Fractionalized porosity obtained by NMR logs can discern bound fluids and free fluids, reveal otherwise hidden pore size variations and determine hydrocarbon composition and viscosity with unique sensitivity. The real-time availability of this valuable information from logging while drilling (LWD) measurements significantly improves drilling decisions to place the well into favorable zones. In addition, under some circumstances, it is safer to perform logging operations with sensors mounted on a bottom-hole assembly (BHA) than with pipe-conveyed wireline tools. Most NMR logging tools, including wireline and LWD devices, record the transverse magnetization signal and its decay rate (T 2 ), because of the simplicity and rapidity of the measurement. Other instruments observe the formation's magnetization buildup rate (T 1 ) upon exposure to a permanent magnetic field. While this acquisition mode is more time consuming, it requires less electrical power and data storage to obtain the same petrophysical information. The T 1 measurement is insensitive to tool motion associated with drilling. The new tool discussed in this paper is the industry's first LWD NMR sensor that performs T 1 measurements in boreholes with diameters ranging from 5⅞" to 6¼". The verification of the new tool followed a three-step testing plan to ensure hardware integrity and data quality. The first testing step checked the consistency between while drilling and relog datasets, including the T 1 spectra and the volumetric deliverables such as total and bound fluid porosity. Real-time logs were compared with post-processed memory data to evaluate downhole processing and data transmission capabilities. The second testing objective was to monitor the consistency among density, neutron and NMR porosities in known lithology (e.g., clean limestones) for the evaluation of tool calibration, activation and echo-level pre-processing. Finally, the new tool was run back to back with a wireline NMR logging tool with high-quality T 1 logging capabilities to validate the accuracy of the LWD T 1 spectrum and partial porosities. The new tool is the latest addition to the industry's LWD NMR technology. It was run in three wells with hole sizes of 6⅛" in three different fields. Two of the wells were drilled in carbonate reservoirs, whereas, the last test was conducted in sandstone. In the carbonate wells, real-time NMR logs provided pore size information in both limestones and dolomitic intervals and helped optimize subsequent formation testing operations for which results were in agreement with the logs. In the sandstone well, the tool revealed grain size variations and provided total porosity, bound water volume, and reservoir permeability. These were key inputs for petrophysical interpretation, model calibration, and completions design.

ABSTRACT A key uncertainty in evaluating a shale gas resource is the estimation of gas in place. In areas, such as the UK, where the shale gas industry is in its infancy and public opinion gives no leeway for error, being able to minimize the number/length of wells drilled has advantages for both economic success and environmental impact minimization. Shale gas refers to fine-grained formations (mudstones) where organic matter has matured sufficiently to produce predominantly gas, but that gas has not migrated any significant distance. Petrophysical analysis is complicated by both petrophysical and geological heterogeneity within the formation, and by the existence typically of both free and adsorbed gas components. The latter is fixed onto organic surfaces and held in place by pressure but these gas phases may occupy adjacent volumes and separating out the two to avoid double counting is an important step. The location of the gas is sometimes considered to be isolated in organic pores or to exist in both organic and mineral pore spaces. The objective of this study is to evaluate a number of contrasting published shale gas methodologies to assess the effect on resource estimates of uncertainties inherent within the models, the sensitivity of different parameters and the underlying assumptions about the physical system made within each model. We present a detailed evaluation of six contrasting petrophysical models with variations in model outputs for gas in place assessed for both absolute values and for downhole trends. A subset of these models are carefully compared to each other, firstly using petrophysical measurements on core samples as model constraints, and secondly ensuring equivalency of parameter values across models. This enables conclusions to be drawn on relative model robustness in relation to the influence of different inputs, different assumptions about the location of the gas, and different statistical techniques employed for analysis. The establishment of a framework of models through which any shale dataset can be run generates a number of key findings; small changes in parameter choices can have a large effect on the absolute value for gas in place; measurements on core (despite the associated uncertainties) are critical to provide model constraints; different assumptions about the location of the gas in place can result in contrasting downhole trends between models. These results have consequences for the selection of downhole intervals for shale gas extraction and highlight the importance of continuing to progress our understanding of shale gas petrophysics and the variations between different geological formations. We conclude that by considering a selection of models with differing underlying assumptions intervals of greater uncertainty can be identified, and this is an approach that can effectively be applied to any shale formation.

ABSTRACT In the harsh environments encountered in oil and gas wells, steel well casings are subject to corrosion. Starting with pitting and thinning at either the external or internal wall, casing corrosion may propagate more seriously turning into holes or splits which cause leaks and environmental damage, seriously affecting production operations. Therefore, corrosion monitoring and timely detection of casing integrity issues is critical. In direct response to demand by the industry for a quantifiable, reliable and cost-effective intelligent solution to accurately evaluate casing integrity, a new ruggedized mandrel based electromagnetic (EM) casing inspection tool has been developed to provide quantitative measurements of casing thickness and inner diameter (ID). The tool also provides a comprehensive analysis of casing material properties. A patented four-segment (quadrant) receiver incorporated within the tool mandrel measures the casing thickness with a 90° circumferential sensitivity based on remote-field eddy current principles. The EM field attenuations and phase shifts from transmitter to receivers are precisely measured using innovative electronics and then quantitatively translated to single-layer casing thicknesses after correcting for variations in the material's EM properties. In addition, within each quadrant, two axially spaced receiving antennas provide a differential measurement to enhance the axial resolution for small defects on the casing wall. Meanwhile, an EM caliper sensor configured according to near field eddy current principles provides dual-frequency measurements which are solved in real-time using an inversion algorithm to provide precise casing IDs and material EM properties, such as magnetic permeability and electrical conductivity. Consequently, the inner or outer casing wall defects can be identified by combining casing ID with quadrant thicknesses during interpretation. In conjunction with a mechanical caliper, the EM caliper is also applicable to further determine the non-metallic deposition on the casing. The newly developed intelligent algorithm significantly simplifies calibration procedures, consistently delivering reliable results. Laboratory verifications have been performed by logging casing samples which are precisely machined with design defects simulating corrosion features. The fundamental interpretation techniques are derived from the corresponding tool responses. The field examples demonstrate quantitative assessment of casing conditions and identification of corrosion damage from the quadrant sensitivity.

ABSTRACT Hyperspectral core imaging (HCI) technology was used to enhance characterization of a thin-bedded reservoir in the Permian Basin. Originally developed for the mining industry, hyperspectral imaging (HI) uses a combination of short-wave infrared light (SWIR) and long-wave infrared light (LWIR) to create a visual ‘map's of the minerals in a core that respond to reflectance principles. HCI, which requires no special preparation other than that the core be clean and dry, can be applied rapidly and provides mineralogical results related to various energy emitted in wavelength spectrum by either halogen bulb reflectance (short-wave quantification) or heat reflectance spectra (long-wavelength quantification). HCI provided detailed, high-resolution mineralogic and textural information of a conventional whole-cored interval and was used to produce interpreted mineral maps to refine stratigraphic models, explain petrophysical responses, and guide selection of plug locations for conventional and special core analysis. Digital HI-derived single mineral curves calibrated to X-Ray Diffraction Data (XRD) were imported as curves to display mineralogical variations with depth alongside open-hole wireline logs. HCI was successfully applied and utilized as an integrative tool across additional data streams, associating open-hole wireline properties, overlays of textural relationships of mineralogical assemblages, and rock typing models with co-location of petrophysical properties to obtain better understandings of mineralogical-to-petrophysical links. We illustrate how hyperspectral imaging can be a powerful aid in geological and petrophysical quantification and property ‘up-scaling’ from SEM- and thin-section scales to depositional-system-level understandings.

ABSTRACT The architectural complexities of carbonates present a challenge for reservoir modeling due to chemical alterations and biological variations. In the absence of core, conventional logs provide limited information about the depositional environment. In contrast, image data combined with mineralogy logs display lithology and detailed features of the texture and structure, which can be used to interpret depositional settings. This paper presents an innovative method to model complex carbonate reservoirs using borehole image data with limited core information. In our study, we integrated open-hole logs, mineralogy logs, an image log, and core data to conduct a detailed facies analysis and determine the appropriate facies association. Those facies association were used to predict facies distribution and locate better reservoir properties. To do so, lithofacies were determined by interpreting an image log based on color contrast and observed features. For instance, evaporites which are shown in bright yellow layers are indicative of a more restricted environment. In contrast, higher energy environments, such as intertidal, can be identified by larger grain size, wavy- and cross-bedding, and higher shell fragment content. In addition, observed paleocurrent directions from bedding planes were used to determine the distribution of sediments in the reservoir and to build a conceptual depositional model. Facies interpreted from the image log and associated to certain depositional environments were calibrated to core data and integrated with reservoir properties, such as porosity and density. These associated facies exhibit a variation in reservoir properties in terms of porosity and permeability that cannot be determined using conventional logs by themselves. For example, mottled and irregular dolomites showed good porosity as opposed to nodular dolomite intervals. Based on observed properties, the interpreted facies were populated across the field and correlated to nearby un-cored wells. A depositional conceptual model was then built to capture the heterogeneity of the reservoir by examining low and high order stratigraphic changes. Low order changes in stratigraphic sequences are construed using facies vertical stacking profiles and global proportion curves whereas higher order sequences were represented using individual well facies. The relative frequency of facies at every well location was the input for propensity analyses and probabilistic depositional environments mapping. To better illustrate the work, an example is presented from a carbonate reservoir in the Permian Basin with image log facies analysis used to build a geological depositional conceptual model and to predict properties distribution.

Abstract Saturation monitoring is a key component that requires special planning of reservoir management in a Water Alternating Gas (WAG) EOR process. Numerous factors have to be taken into account when planning surveillance, from fluids to filling history and compartmentalization. The alternating cycles are also important in determining when and where to gather the data. Within the WAG EOR process itself, there are field specific drivers that ensure the miscible process delivers an efficient sweep. Quantifying saturation in WAG EOR is extremely challenging. We cannot treat this application as a simple three phase time lapse pulsed neutron problem. The end point values of various nuclear attributes will change with the fluids composition during production of the WAG cycles. Changes in water salinity, oil density, gas composition, pressure variation and deviation from compositional gradients will all potentially modify the notional end points. Access to "minimal" well and reservoir information will secure a robust saturation extraction from the application of multiple nuclear attributes. A more unique solution would require special modes of data acquisition, tool modifications or well conditions. Well access can be challenging on a number of fronts from production deferral, limitations on personnel on board and costs of data gathering. Applying learnings from previous data gathering campaigns combined with evolving technologies in the area of multidetector pulsed neutron and memory conveyance can make surveillance in WAG EOR an efficient tool for reservoir management. This is an arena where reservoir engineering and petrophysics needs to work together. This paper presents learnings from a Norwegian field under WAG injection and addresses the data acquisition, interpretation and integration within the reservoir model.

Abstract Until recently, an exploration petrophysicist expecting a pay zone with good porosity and high resistivity might simply have disregarded a conglomerate reservoir on the Norwegian continental shelf. The conglomerates observed in the North and Barents seas are mineralogically complex and present either low-resistivity/low-contrast or low-porosity/low-hydrocarbon pore volume conditions. However, in recent years, newer measurements and evaluation techniques have become available, which in addition to conventional logs, have been used to enhance the petrophysical evaluation of a number of important oil and gas conglomerate discoveries made in both siliciclastic and carbonate settings in the North and Barents seas. These Jurassic-Triassic aged reservoirs hold economically viable contingent reserves and exhibit production rates varying from 1,000 BOPD to more than 3000 BOPD. Conventional logs acquired in the carbonate conglomerates of the Barents Sea and the conglomeratic sandstones of the North Sea have proven difficult to interpret. Low porosities, varied mineral distributions, heterogeneous pore systems, low resistivity contrasts between hydrocarbon- and water-bearing intervals, variation in rock texture, and the presence of immovable hydrocarbons can represent a formidable petrophysical evaluation challenge. Even at depths where the presence of hydrocarbon is established, formation testing in some cases results in either tight (low-mobility) tests or flows water during sampling. For this reason, hydrocarbon moved by mud filtrate invasion is often a better indicator of producible pay than that inferred from favorable hydrocarbon saturations alone. We present an integrated petrophysical evaluation technique combining induced gamma ray spectroscopy measurements, used to create a reliable lithology/porosity model, with dielectric dispersion measurements, used to provide fluid saturations. The resulting analysis accurately reveals the subtle differences in shallow versus deep saturations that are critical in predicting movable hydrocarbon in the conglomerates. Provided as a timely delivery prior to formation testing, the predictive power of the petrophysical evaluation is illustrated by agreement with the subsequent formation testing data. Four field examples, one from the North Sea and three from the Barents Sea conglomerate reservoirs, are discussed in this paper. The proposed evaluation technique is based on an integrated petrophysical analysis of dielectric dispersion, induced gamma ray spectroscopy, and standard log measurements. The method has consistently proven successful at defining intervals containing producible pay in multiple wells across the complex and varied conglomerate discoveries on the Norwegian continental shelf.

Abstract Gamma ray (GR) logs from infill wells in heavy oil development projects frequently exceed 1000 GAPI, but only through the hot vapor cloud that develops as injected steam displaces heavy oil. GR values in the same sands that are liquid-filled, and immediately below the vapor-filled rock, are typically less than 100 GAPI. Previous work (O'sullivan, 2008) shows that high GR values are caused by drilling-related cooling of vapor-filled rock. GR is thought to increase when water- and hydrocarbon-molecules, with solubilized radon atoms attached, are concentrated by 100 times or more as they approach the dew point and condense around a chilled well. After the chilled well begins to re-heat and equilibrate with the hot reservoir (36 hours or less) GR returns to normal levels. An experiment demonstrated that the cycle of GR increase and decrease can be repeated indefinitely, simply by chilling the well and then allowing it to warm back. Samples of the condensed vapor have not been acquired, nor has condensed vapor gamma ("CVG") been generated in a lab under controlled conditions, so much remains to be learned about the nature of CVG, and how it can be used to understand reservoir processes. To put the condensed vapor gamma (CVG) effect into context, logs from thousands of heavy oil development wells from two large oil fields of the San Joaquin Valley, California were systematically reviewed. GR logs through vapor-filled rock for reservoirs in Midway-Sunset Field show that CVG amplitude is higher (≈ 2000 GAPI) in poorly-sorted rocks than in well-sorted clean sands (≈ 200 GAPI). The difference is driven by higher residual oil saturation in poorly-sorted rocks. Higher radon solubility and vapor pressure for oil, compared to water, lead to higher CVG values. GR logs through well-sorted sands in Belridge Field, were anticipated to be low, and similar to those for well-sorted sands in Midway-Sunset Field. Instead, the CVG amplitude is unexpectedly high, exceeding 10,000 GAPI. A cross section of seven closely-spaced wells, drilled within an eight-year time span, shows that these very high GR values strongly correlate within a 60-foot interval. For the entire field, maps that track the year-by-year onset of high GR show interesting, but unexplained patterns that are restricted to limited areas and time intervals. The difference between the CVG responses in the two fields may be explained by the observation that, for Belridge Field, the very high GR values occurred years after the steam flood on this reservoir peaked, during the time when development of a deeper reservoir containing light hydrocarbons was accelerating. CVG amplitude may have increased when the heavy oil vapor cloud was overprinted with light hydrocarbon from the deeper reservoir. With the light hydrocarbon, vapor pressure increases and improves the efficiency of radon absorption. The observations suggest that, under certain conditions, it is possible to develop a method for in situ evaluation of vapor properties. Although the condensation-induced gamma signal has only been documented to occur in wells drilled in heavy oil steam floods, the effect could occur in any reservoir containing condensable vapor, provided that the vapor can be cooled to the dew point. Applications include evaluation of vapor composition, identification of barriers, and time-lapse monitoring of changes in vapor properties as an indicator of enhanced recovery process efficiency. Controlled generation of CVG in the laboratory is a logical next step toward improved understanding of this phenomena. Continuous in situ observation and monitoring of CVG is also recommended, in order to explore the linkage between CVG and development activities.

Abstract The ability to measure GOR and asphaltene gradients by downhole fluid analysis (DFA), and to perform thermodynamic analysis of these gradients with the cubic EoS and the FHZ EoS mandates understanding of the origins of these gradients. Equilibrated asphaltenes measured by DFA are a commonly used indicator of reservoir connectivity; understanding these gradients is important. The variations of different crude oil components measured today are a function of charge history. In addition, these variations are a function of in-reservoir fluid processes that, in some cases, can cause fluid distributions to partially or totally equilibrate thermodynamically. Nevertheless, different physics can govern each of these distributions and can yield differing extents of corresponding equilibria. Here, petroleum system modeling is used to create different plausible initial reservoir fluid distributions immediately after charging, where the layer-cake "Stainforth charge mechanism" is presumed. Charges that are relatively homogeneous versus those of greatly differing thermal maturities are considered. Subsequent to charging, diffusion is forward modeled. For a charge of greatly differing thermal maturity, the initial versus final, equilibrated gradients in GOR and asphaltenes are seen to be similar, thus equilibrium is readily obtained in geologic time. In contrast, in this case, the large initial gradient in liquid fingerprints and biomarkers (in C8 - C25 range) is very dissimilar to the final homogenous equilibrium distribution of these components, thereby hindering attaining equilibrium. Consequently, a single oil column can exhibit equilibrium distributions of GOR and asphaltenes with disequilibrium in oil fingerprints and biomarkers. In contrast, a homogenous charge can yield the opposite, equilibrium of fingerprints and biomarkers, and disequilibrium of GOR and asphaltenes. Essentially, the ‘thermodynamic distance’ from the initial condition (end of charge) to equilibrium determines whether the inherently slow process of diffusion can yield equilibrium; large thermodynamic distances hinder equilibrium, while small thermodynamic distances allow attainment of equilibrium. More complex cases will be considered in the future involving convective currents and more complex charge models.

Abstract Nuclear Magnetic Resonance (NMR) responds to variations in petrophysical properties of hydrocarbon-bearing formations by logging information about the pore space and the fluids contained therein. Two new approaches have been developed for evaluating NMR data in chalk. One approach is for reservoir characterization by deriving pore throat radii from NMR T 2 distributions and estimating an NMR-based permeability by applying a fluid substitution method for hydrocarbon correction. The other approach is for Managed Pressure while Drilling (MPD) optimization through the assessment of mud filtrate invasion detected by NMR logging while drilling (LWD). The basic control on present-day saturation of a chalk reservoir is in most cases capillary pressure, owing to size of pore throat radii and variations of the same. Chalk typically exhibits a mono-modal pore throat radius distribution and a corresponding mono-modal T 2 distribution. A theoretical model of a water film residing on the pore surface describes variations in the NMR response as a function of fluid saturation. The model defines a fluid substitution method for hydrocarbon correction used for estimating the NMR response at full water saturation. It enables a conversion from the mean T 2 value, T 2gm , to the average pore throat radius and predicts that water and light hydrocarbons in chalk can be easily separated by a cutoff in the T 2 distribution for calculating water and hydrocarbon saturations. NMR LWD field data from development wells in a mature, low-porosity North Sea chalk field drilled with water-base mud and using MPD techniques were evaluated for saturation. Invasion of drilling fluid (the degree of which can vary considerably along the well) is governed by the pressure differential between the well and the formation in conjunction with rock permeability. Substantial invasion of WBM filtrate can be inferred qualitatively from real-time T 2 distributions. More subtle invasion is identified where the shallow reading NMR-based water saturation exceeds the conventional deep-reading resistivity-based estimate of saturation. Based on these observations, refinement of MPD is enabled by adjustment of equivalent circulating density (ECD), whilst obtaining detailed information about variations in permeability of the reservoir along the well bore. Based on core data calibration average pore throat radii were calculated from T 2gm in all wells, varying in the range of 0.1 to 1 µm. Using multiple linear regression (MLR) with pore throat radii and porosity as inputs, native water saturation was established exclusively from the invasion-affected NMR data. An excellent match to the conventional resistivity-based saturation can be achieved provided the conditions controlling present-day saturation are uniform. This method was found to be useful for investigating whether saturation observed in various wells could be considered at standard drainage condition or affected by imbibition. Consequently, NMR LWD yields insight not only into pore space variations along the well bore, but also on the geological genesis of different parts of the reservoir. Furthermore, NMR T 2gm -based permeability was calculated and calibrated against an existing porosity permeability correlation. Due to the implicit incorporation of pore size variations in T 2gm , the NMR-based permeability shows a much more pronounced variation compared to permeability calculated from the traditional porosity-permeability transform.

Abstract The iGEM-4D research project combined petrophysics, geophysics, geomechanics and digital rock modelling to investigate and predict the 4D seismic responses of Albian carbonate reservoirs in offshore Brazil using 48 core plug samples. The plugs include a range of lithofacies from peloidal grainstones, oncolitic packstones to floatstones. X-ray/SEM images and petrophysical properties were measured prior to destructive geomechanical and rock physics testing of the plugs: helium porosity and permeability, brine-saturated low field NMR spectroscopy, benchtop ultrasonic velocity measurement, and dielectric spectroscopy. For the dielectric study, discs of 7–9 mm thickness were cut from the end of each core plug, and these were measured in dry, humidified and brine-saturated state in a custom parallel plate cell. The main suite of measurements used direct coupling of the fluid saturated rock to the gold plated electrodes; the brine-metal interaction inevitably causes electrode polarization effects that limit the lower frequency range of the measurement. A protocol developed at CSIRO was used to extend the range of measurement to low frequencies using polymer film to block electrode contact and eliminate polarization. The full range of permittivity measurement is thereby extended from sub-MHz to 110 MHz. While the rocks are essentially clay free, rather weak surface polarization can be discerned in the low frequency brine-saturated data and in the response of the humidified samples. The spectra also indicate that the water affinity of the pore surfaces is weak, perhaps from incomplete oil cleaning of all the fine pore space by toluene-methanol treatment. It is also possible that treatment changed the wetting property of the pore surfaces to become hydrophobic to some extend. At the 100 MHz frequency the data fit a CRIM mixing law very well, and this would imply little dispersion from 100 MHz up to the GHz range would be expected for these rocks. We found moderate correlations between porosity, permeability and dielectric properties of the carbonates that were superior to correlations between conductivity and the pore/flow characteristics. An unexpectedly strong correlation was found between the dielectric constant and the slowness of ultrasonic waves measured at the benchtop on the same disc samples. This may represent the analogy between CRIM and a time-average wave speed equation. The dispersions in conductivity and permittivity with and frequencies << 100 MHz are not well fitted by a simple model based on the Hanai-Bruggeman description for grain / brine inclusions with a single shape factor (analogous to an Archie m exponent) for the pore space. This is expected as the pore structures seen in SEM images and x-ray micro-CT images of the samples are complex and display a large range in size and aspect ratios. Indeed, NMR analysis using conventional CPMG measurement of T 2 completely fails to capture the pore size (< 100 µm: meso- and micro-scale) distributions of these rocks because of pore coupling effects and weak surface relaxation. While our work is not definitive, it does suggest that dielectric laboratory and logging methods may have advantages for pore structure characterization and for estimation of some useful physical properties in carbonates (e.g. elastic moduli), especially when NMR requires slow logging speeds and multi-dimensional acquisition and processing methods to overcome pore coupling problems.