The exploratory projects of hydrocarbons in the Parnaíba Basin have primarily targeted Poti and Cabeças Formations. With the rich geological knowledge obtained from the drilling of wells, the Longá Formation is viewed as a potential new exploratory play. This formation, which some studies reckon that can act as seal or source-rock, is characterized by the intercalation of shales, siltstones, and sandstones. During the drilling of a well, with the subsequent detection of gas, three 18 m long whole-cores were extracted for geological and petrophysical studies. In addition, a complete set of conventional and nuclear magnetic resonance (NMR) logs were obtained along with laboratory analyses of routine core analysis (RCA), capillary pressure, NMR, X-ray diffraction (XRD), and rock mechanics, for a complete petrophysical evaluation. The Longá reservoir is a complex reservoir with millimeter-thick laminations and reservoir layers with conductive minerals that suppress the resistivity curve. As a result, the log data had to be integrated with core data and ultimately a Domain-Transfer analysis model in uncored wells to correctly estimate petrophysical properties and make development decisions. The integration of core-log data made it possible to obtain important information about the depositional environment, lithology, reservoir characterization, calibration of the main petrophysical parameters, and mechanical properties of rocks , which can help realize hydraulic fracturing, thereby contributing to production optimization and risk reduction in exploratory projects. The productivity of the well increased by approximately 500% after stimulation of reservoir. Furthermore, the subsequent drilling of a few more exploratory wells revealed the first commercial field of the Longá Formation in the Parnaíba Basin. INTRODUCTION Petrophysical evaluation of thinly laminated reservoirs presents great complexity, especially regarding the estimation of hydrocarbon volume in place. Conventional well logging tools have a vertical resolution, which is larger than the size of the laminations in thinly laminated reservoirs, and thus fail to solve the petrophysical properties of these small layers. In addition, the presence of clay minerals generates an excess conductivity that affects the resistivity curve. The above- mentioned effects are known well in the petrophysical technical literature as complicating factors for the generation of reliable models. Additionally, this case study presents a greater difficulty due to the presence of complex mineralogy that contains metallic, heavy, and conductive minerals, thereby corroborating the need for complementary studies on core-log integration as a way of calibration of the main petrophysical parameters. Geology is strongly related to the in situ measurements performed by well logs, and thus helps in deeply understanding the spatial distribution of petrophysical properties and geometry of the different lithologies. Given the type of reservoir that this work presents, special emphasis will be given to understanding the relationship between geology and petrophysics.

Understanding the volumetric concentrations of hydrocarbon and water in a producing reservoir is a critical component of predicting well performance, designing well placement and field development planning. Core testing procedures and petrophysical models in unconventional shale reservoirs have always faced the challenges of establishing representative in-situ water and hydrocarbon saturations. When using existing techniques of core calibrated petrophysics, actual well production often varies significantly from expectations. These variations may include scenarios such as lower overall oil production or strong oil production that is accompanied by large volumes of produced water. This has a serious impact on the development of major U.S. unconventional plays such as the Wolfcamp, Spraberry Shale, Austin Chalk, Eagleford, among many others. Core taken from these formations is the key to better understanding what fluids are present and in what quantities. It is well agreed upon that changes in pressure and temperature as rock is taken from downhole, handled and transported to a laboratory facility affect the contents of the pore system. This generally results in a varying amount of void space that is measured in the rock at the lab. Standard practice calls for treating this void space as previously occupied by oil that has volatized during coring operations, transport, and core testing. Therefore, estimates of hydrocarbon filled porosity are made using the volume of oil extracted from the rock during testing (whether thermally or via solvents) combined with the volume of void space measured. Water Saturation is assigned a value based on the actual water measured from the rock during the extraction process. However, fluid phase behavior in nano-pore systems is not very well understood. Pore wettability and permeability are also important factors that may control what fluids are lost from the system. Given these uncertainties, the assumption that void space is associated with volatized hydrocarbon does not hold true. Through updated procedures and use of new equipment, it has been shown that a significant portion of this void filled porosity is occupied by formation water at reservoir conditions. The discussion below will show several experiments validating this idea including: comparisons between preserved and non-preserved core samples, re-testing old core to measure fluid changes with time, nuclear magnetic resonance (NMR) scans, flow-through and fluid imbibition studies among others. Where available, NMR T1-T2 logs will be used as a downhole water saturation reference. Additionally, log interpretations calibrated to this new water saturation will be shown and compared to well performance.

In this paper, we examine fluids interpretation techniques in a prolific oilfield in offshore West Africa. The reservoir rocks are dominated by Cretaceous limestone, with a small fraction of dolomite and siliciclastic minerals. Due to concerns of radiation hazard, the drilling team has selected a sourceless logging program, consisting of LWD NMR, resistivity and formation tester, to log the reservoir section in 6.5" holes. Therefore, standard log interpretation, which relies on multi-mineral analysis, is no longer viable. The purpose of this study is to answer questions related to asset appraisal and development with these limited measurements. Whole cores were collected from both of the geological structures of the oilfield and the lab measured porosity, permeability, water salinity, Archie m and n and Dean-Stark Sw. Comparison of core and NMR log indicates that NMR total porosity is not affected by hydrocarbon in the pore space. We use a statistical method called factor analysis to deconvolve independent fluid modes, such as clay bound water, capillary bound water and oil+oil-based mud (OBM) filtrate, from the T2 distribution. The number of modes to solve for is determined by principal component analysis. The free fluid T2 cutoff is chosen based on the identified modes. The NMR irreducible water saturation ( S wirr ) computed with this cutoff agrees with Dean-Stark Sw, measured on core samples assumed to be fully invaded by OBM. Continuous Sw is calculated with Archie’s equation with lab-measured parameters and validated against Dean-Stark Sw above the transition zone. The Timur-Coates model is used to estimate matrix permeability, using core-calibrated multiplier and the T2 cutoff from factor analysis. The permeability, Sw and S wirr curves are then used to compute continuous effective permeability to water and oil. The first application of this interpretation workflow is to confirm the free water level (FWL) derived from pressure gradients. We found the Sw profile largely controlled by heterogeneity in rock textures. Good-quality rocks have negligible transitions zones and contain little free water above FWL. Poor-quality rocks have longer transition zones, but the relative permeability to water is too low for the water to flow, as confirmed by production. Pressure depletion suggests excellent connectivity within the reservoir, so these poor-quality rocks are considered a local feature. Log analysis confirms the reservoir-wide FWL, which translates to a significantly increased OOIP over initial estimation. The second application is perforation design. Zones with good porosity and low mobile water volume are selected for perforation and a safe distance is maintained from FWL. As a result, all producer wells exhibit zero water cut.

In many unconventional oil-bearing reservoirs it is generally recognized that the system has mixed reservoir wetting properties. Part of the porosity system is water-wet and part is oil-wet. Unless specialized analytic techniques have been applied to rock samples, it has not been possible to define wetting characteristics. Additionally, there are no readily-available methods to address the issue of fluid flow in mixed wetting environments. In previous publications (Holmes 2014, 2017, and 2019), the authors described a technique to quantify effective organic porosity in the shale fraction as compared with the effective inorganic porosity in the clean fraction using triple-combo well logs. Porosity/resistivity cross plots were also presented to demonstrate the effective inorganic porosity is water-wet and the effective organic porosity is frequently oil-wet. This publication expands on the prior findings to include examples where the effective organic porosity is interpreted to have mixed wetting characteristics controlled by absolute values of organic porosity. The degree of wetting can be quantified, controlled by absolute values of organic porosity. For unconventional oil reservoirs, careful examination of the porosity/resistivity cross plots for the effective organic porosity indicates that the data for water saturations less than 100% often align on non-linear trends. In standard petrophysical analysis, linear alignment is interpreted to honor the Buckles relationship ( porsosity × irreducible water saturation = constant ) and the slope of the data is a direct measure of the difference between the Archie cementation exponent (m) and the Archie saturation exponent (n). For the interpretation presented here, values of the changing slope can be calculated to define, point-by-point, the changing value of "n" ("m" is kept constant), to be used in calculations of water saturation. Profiles of "n" often show a consistent and gradual increase from about 2 (water-wet) to 3 or more (oil-wet) as porosity increases. Examples from a number of unconventional oil-bearing reservoirs are presented. Some are unequivocally oil-wet in the effective organic porosity fraction (Bakken and Wolfcamp), and others are interpreted to be of mixed wetting (Niobrara and Eagle Ford). The results show that mixed reservoir wetting characteristics can be estimated from readily available petrophysical data. Implications as to fluid flow behavior are significant, as well as the history of organic porosity generation through time.

The acquisition of open hole logging data is not always guaranteed because of difficult drilling environments. In such cases, formation evaluation, and thus completion program, becomes a real challenge. The situation becomes more complex when dealing with unconventional reservoirs with very tight carbonates and organic carbon-rich formations. This paper presents a method to measure the total organic carbon (TOC), which, in this paper, represents the organic carbon in the matrix (kerogen and coal), and to estimate oil saturation in such challenging environment. A suite of wireline tools (GR, Spectralog, Density, Neutron, Nuclear Spectroscopy), was run through 7 5/8″ casing to evaluate the formation and to quantify TOC and the oil in the pores. The nuclear spectroscopy tool, which was the master tool, measures the total carbon in the formation. Part of this carbon is attributed to the inorganic matrix (carbonates), another part is attributed to the organic matter in the matrix (kerogen), the remaining carbon, or excess carbon, is mainly the carbon inside the pores. The process consists of integrating the conventional logging data, the spectroscopy data, the core data and some geological constraints to estimate corrected porosity, mineralogy and TOC in the kerogen-rich intervals. The excess carbon, which is not attributed to the matrix and TOC, is used to estimate oil saturation. Finally, core data are used to validate the analysis results. The presented methodology has been applied to a cased-hole well with no open hole data previously acquired, due to drilling issues. The primary target of the well, in the deep section, produced water; then the operator decided to revisit the second target and complete it for testing. It has to be pointed out that over the well cemented intervals, the results showed a very good matching of the corrected total porosity and the core total porosity. Relying on TOC and saturation analysis results, the operator selected the most promising intervals to be tested. Testing results have shown excellent matching between production results and oil saturation analysis results. TOC and oil saturation quantification using nuclear spectroscopy technology and core data results showed its success in both tight carbonates and organic carbon-rich reservoirs. This method will be a solution to evaluate and complete any wells with no open hole data acquired, and also to evaluate and complete the unconventional formations where the conventional methods have shown their limitations.

The Rumaila field is in South East Iraq and contains multiple reservoir intervals, including the Upper Cretaceous Mishrif carbonate reservoir, one of the major reservoirs in the world, that has been producing for more than 50 years. One of the key challenges in the Mishrif is to characterize the pore structure distinction between primary and secondary porosity. The secondary porosity in the form of large pores, if present, dominates the petrophysical properties, especially permeability. Advanced logs e.g. Nuclear magnetic resonance (NMR) and image logs can be utilized to understand the variations in pore structure both qualitatively and quantitatively. In this paper we focused primarily on four new wells with very comprehensive logging and coring programs. NMR logs were acquired using different tools and pulse sequences. This resulted in uncertainty in porosity and T 2 distributions and consequently complications in the NMR interpretation. We observed two key issues: porosity deficit due to lack of polarization and T 2 distribution truncation due to the low number of echoes. We used a single pore model to reproduce the NMR response in different pore sizes and fluid types for different pulse sequences. The results showed that the NMR response, especially in water (water-based mud filtrate) filled large pores, is sensitive to polarization time, echo spacing and tool gradient strength. NMR log data confirmed the modelling results. We recommended an optimum pulse sequence and tool characteristics to fully capture the heterogeneous rock and fluid system in this carbonate reservoir. NMR logs, when available, were the primary tools to identify the large pores. We present a consistent workflow for NMR log analysis that was developed to identify and quantify large pores and extended to all wells in the field. We used advanced NMR interpretation techniques e.g. Factor Analysis (NMR FA, Jain et al, 2013) in a series of oil wells drilled with water-based mud. Using Factor Analysis, we identified a cut off value of 847 ms for large pore volumes. In this manuscript we also present an integration of laboratory measurements e.g. NMR, mercury intrusion capillary pressure data, whole core CT scanning and thin section analysis in our interpretation workflow. We also compared the large pore volume from image logs with NMR logs and other laboratory data and observed very consistent results. All the available information was integrated to build an "NMR-based" petrophysical model for porosity, rock type, permeability and saturation determination. The NMR-based model was very comparable with the classic FZI rock typing. The results of this study were used to modify the NMR acquisition program in the field and to build a petrophysical model based on only NMR and image log measurements for carbonate reservoirs. In this paper, we will discuss NMR modelling and corresponding log data from various wells to confirm the results. Furthermore, we will present novel interpretation workflow integrating laboratory measurements and log data which led to the modification of the NMR acquisition program in the field and creation of a data-driven petrophysical model based on only NMR and image log measurements for carbonate reservoirs.

Geothermal projects are rapidly developing in Continental Europe to provide an alternative energy source. These projects typically involve a doublet of a producer and injector well, which are typically vertical wells drilled with minimal measurement technology. We discuss how advanced wireline measurements guided the decision making for completion strategy in a sub-horizontal geothermal well in the suburbs of Paris, France, which at the time was a world premiere in geothermal well design. In addition, we will describe how these measurements aided understanding of the overall structural model. The project provided a 150% increase in geothermal productive/injective capacity vs. previous conventional approaches. The study was conducted in the Cachan project in the Paris Basin, which was developed to provide a city on the outskirts of Paris with geothermal heat. The project targets thin porous oolitic layers within a dolomite formation as an excellent geothermal target to produce from. The well was geosteered with Logging While Drilling (LWD) density images after which wireline Nuclear Magnetic Resonance (NMR) and dipole sonic measurement tools were operationally efficiently conveyed on tractor throughout the long horizontal drain section. A multi-physics approach combining the density images, high resolution magnetic resonance poro-permeability data and oriented sonic measurements was applied to study the homogeneity of the layers along the well and determine the flow properties and possible compaction effects. NMR logs were primarily used to assess the porosity and permeability variations of the oolitic reservoirs with high resolution, highlighting the intervals with the highest fluid movability through the thin layers. NMR measurements were also applied to describe the pore system and assess the fluid movability through the thin layers. NMR carbonate porosity partitioning analysis was used to classify rock type with similar reservoir quality and assist with the definition of rock properties cutoffs for development strategy. In addition to typical applications for rock mechanics and petrophysics, the sonic data in combination with the azimuthal density helped explore any possible effect of the proximity of the adjacent layers within the thin oolitic section (in the order of 1 meter). By combining measurements from different spacings and taking the opportunity to analyze the non-standard individual azimuths from the sonic technology, a more detailed structural model was obtained after integration with the density image. This enabled understanding whether permeability variations are truly related to layer variations or a result of the measurements sensing properties of an adjacent layer and defining the heterogeneity of the oolites. Moreover, the lateral continuity of the layers and structures were captured by exploring the far field sonic reflectors imaged with a dipole sonic source. Multiple reflectors could be traced over hundreds of meters providing not only a good picture of the overall homogeneity but also how layers extended away from the wellbore. This enabled obtaining a detailed understanding of the structures along the horizontal well. Reflectors could be observed up to 40 m away from the wellbore.

In mature fields, pulsed-neutron logging is commonly used to solve for remaining saturation behind the casing. For years, sigma-based saturation has been used to calculate gas saturation behind casing; however, the high dependency of sigma-to-water salinity of the formation, especially the low dynamic range at porosity near 12 p.u., has proven to be challenging in the low-porosity, gas rock. A new measurement from the third detector from a multi-detector pulsed-neutron tool (MDPNT) is proposed to provide a better estimation of the gas saturation in a low-porosity reservoir. Two sets of independently measured sigma and the third detector were taken in a cased hole well, with a dualtubing system of a long string and short string. For the third-detector measurement, the measurement was based on the ratio of slow capture gate and inelastic gate component from the decay curve created by the long detector. This ratio can be used to detect gas in a tight reservoir with a minimum salinity and lithology effect. This data will then be used to calculate the gas saturation from the third detector, and the result is compared to sigma-based gas saturation. At an interval where the porosity is above 12 p.u., the sigma-based gas saturation and MDPNT-based gas saturation are very much in agreement. However, in a low porosity reservoir near 12 p.u. or below, the sigmabased measurement starts to show its limitation. Meanwhile, the MDPNT-based gas saturation clearly shows the remaining gas saturation where sigma-based measurements failed to detect. The subsequent decision was made based on the log analysis result, and perforation was done at a potential interval based on MDPNT result. The results from the production test confirm the MDPNT-based gas saturation with 700 MSCFD gas production added. This study showcases a new technology to solve a lowporosity gas reservoir issue where a sigma-based measurement underestimate the remaining gas saturation. Using two different measurements in the same well, the results from the MDPNT measurement demonstrated a better result compare to the sigma-based measurement in low-porosity rock.

For over 40 years Pulsed Neutron Logging (PNL) has been used in the industry to determine hydrocarbon and water saturations for reservoir saturation monitoring. Earlier, this technique was mainly used for time-lapse contact movement analysis and for a qualitative assessment of the saturation. Present-day PNL tools can perform a quantitative assessment of petrophysical properties of the reservoir including mineralogy, porosity and saturation. The ability to record multiple independent measurements expands the applications of cased-hole evaluation to environments otherwise not accessible and to cases where a standalone evaluation is required. PNL technology has been successfully used in the West Netherlands to estimate petrophysical properties, mineralogy, and for diagnosis of bypassed hydrocarbons and depleted zones. The cased-hole environment here tends to be complicated by the presence of multiple casing strings and completion hardware in the borehole, with variable annular and near-wellbore fluids. Every measurement is used and interpreted in relation to its statistical uncertainty and level of interpretability. In a complex scenario, near-wellbore conditions and well dynamics determine to what extent a standalone cased-hole evaluation can be performed. The paper describes an example of log acquisition and data integration in a complex depositional environment. Cased-hole logging is performed to determine the oil potential in Lower Cretaceous reservoirs, following the discovery of an oil lead in a nearby field. Important reservoir properties are measured through-casing and combined to compute porosity and mineralogy. Water saturation estimation done using porosity, mineralogy and measured sigma values is compared to oil saturation computed from total organic carbon (TOC) direct method. Carbon/Oxygen (C/O) ratio could not be applied in this wellbore environment because of the presence of multiple strings, large 12.25″ borehole, gas in the tubing and unknown mud filtrate in the invaded zone. As a result of the borehole conditions, the Near Carbon-Oxygen ratio versus Far Carbon-Oxygen ratio has a very narrow envelope (limited dynamic range) that cannot be interpreted. The presence of oil-based-mud invasion in combination with a large borehole limited the ability to confidently resolve the oil saturation in the uninvaded zone from TOC measurement. If considered independently, this could lead to an overestimation of the oil saturation of the uninvaded zone, as suggested by the comparison with sigma-based saturation computation. A comprehensive evaluation approach that integrates cased-hole neutron porosity and sigma, elemental dry weights from capture and inelastic spectroscopy, including TOC, with resistivity from logging-while-drilling (LWD), is applied to reduce the reservoir characterization uncertainty and facilitate informed decision making. The combination of these log measurements into a quantitative multi-mineral solver analysis proved very useful in demonstrating that the oil lead identified in the formation has only residual oil and should not be pursued further as an appraisal opportunity. A review and comparison of different interpretation methods with their associated uncertainties is required to constrain the petrophysical model. This further highlights the importance of data integration to maximize confidence in the evaluation results in such complex boreholes. The right amount of data exchange and communication between various disciplines led to a sound conclusion of the project that halted the execution of the appraisal opportunity; thus, avoiding an unnecessary expenditure of several million euros

Porosity-resistivity-permeability relationships are critical for reliable formation evaluation. Archie’s equation, for instance, has been widely used for quantification of petrophysical properties. However, several fundamental questions remain concerning the reliability and accuracy of such relationships and their range of validity. First point of concern is the physical meaning of the associated parameters and their controlling physical properties, such as the porosity exponent, m . Second, the selection of parameter values can be ambiguous. Third, the reliability of the relationships becomes questionable when extrapolating them to spatially complex rocks, or to a wider porosity range. Underlying these questions is the fundamental notion of petrophysical rock classes , wherein a rock class is defined as exhibiting common petrophysical equations and constant associated parameters, regardless of porosity. In this study, we use microfluidics (micromodels) augmented with pore-network modeling to shed physical intuition and quantify the range of practical validity of fundamental porosity-resistivity-permeability relationships. We develop an experimental system that provides precise electrical measurements of microfluidic chips with controlled pore-space patterns. A combination of experimental and numerical methods is used to investigate the effects of different pore geometries, pore-space evolution processes, and bimodal pore-size distributions on electrical resistivity and permeability. Further analyses of flow patterns and interstitial flow velocity distributions from pore-network modeling provide valuable information about flow phenomena in porous media. Results indicate that both pore-size distribution and its evolution during diagenesis considerably impact the porosity-resistivity-permeability relationships. Either a large pore-size variation or a significant porosity decrease for small pores gives rise to an increase of m . In such cases, flow of electrical current is spatially localized and the fraction of porosity responsible for total conductivity decreases; m is not constant for all porosity values due to changes in interstitial flow patterns. In the case of bimodal pore-size distributions, the formation factor-porosity relationship is not linear in log-log scale because the associated flow is primarily dependent on the fraction of macropores. These results suggest that using porosity alone as pore-space property is inadequate when describing electrical flow behavior in complex rocks. We identify several flow-pattern parameters to describe effective flow underlying electrical conductivity, as well as to define and assign electrical rock classes based on available core measurements.

This work compares traditional petrophysical workflows to machine learning methods to compute porosity and permeability in the Inyan Kara Formation of the Dakota Group in the Williston Basin. Quality of dataset (variability, size and robustness), basic theoretical approach, method, results, applicability in the geological area and predictive power are the fundamental basis of this comparison. Produced water disposal into a shallow Dakota Group presents challenges to nearby development drilling, potentially generating high-pressure zones in the overburden. Accurate pressure prediction for the Dakota is very valuable for drilling design and development timing decisions. Along with disposal volumes, porosity is the critical variable which determines the formation pressure. The Dakota does not contain hydrocarbons resulting in limited porosity log data. However, there are abundant resistivity and gamma ray logs through this interval. Therefore, a data analytics model is used to compute porosity based on location and available resistivity and gamma ray logs. Also, a modified Archie’s equation is used to compute porosity from resistivity and gamma ray data. Data analytics-based porosity and resistivity-based porosity are compared with available neutron-density log derived porosities. The team working this project comprised a Petrophysicist, Reservoir Engineer and Geologist who compiled, analyzed and built a geo- and reservoir model based on this work to predict formation pressure in the Dakota Sands. INTRODUCTION The Williston Basin, North Dakota, has become one of the largest oil producers in the United States. Large volumes of water are being produced along with oil, most of which is disposed in Inyan Kara formation of the Dakota Group. The Dakota Group is situated between the surface and the zones targeted for oil and gas development drilling. Water disposal into this shallower formation presents risks to nearby development drilling, potentially causing high pressure zones in the overburden. Accurate pore pressure predictions for the Dakota Group is very valuable for drilling design decisions. Along with disposal volumes, porosity is the critical variable which determines the formation pressure.

The Colombian Caribbean region has become an important exploratory target, and recent discoveries confirm its potential as a gas province to overcome the expected-near future gas deficit. A petrophysical and dynamic characterization workflow was implemented for this challenging deep water play, where the depositional environment is the result of turbidity current processes. The reservoirs consist mostly of thin to very thin sand layers, corresponding mainly to the Ta, Tb, Tc divisions of the Bouma Sequence as observed in the cored intervals. Bouma divisions Td and Te, are related with lowest rock quality and represent the non-reservoir intervals. The greatest challenge in the characterization of this particular reservoir is the vertical resolution, given the very low thickness of the layers, which become very difficult to detect using standard resolution logs. Thus, tomography images, resultant CT-Scan curves, and their integration with routine and special core analyses, were used to reveal the true nature of this complex reservoir. The proposed methodology focuses on the integration of Routine and Special Core Analysis for the petrophysical and dynamic characterization of the reservoir, where the pore throat radius distribution from high-pressure mercury injection becomes the basis of the differentiation between what is considered reservoir and what is not. Pore throat radius estimated from High Pressure Mercury Injection (R35) correlates extremely well with textural features and clay content in the rock therefore this parameter (R35) was used to define the different classes for rock typing. The approach taken was to develop a multilinear regression model of R35, as a function of very high-resolution tomography outputs in the cored zones, and then see how it may be extrapolated to the uncored zones using available high resolution logs. Special petrophysical analyses such as NMR Low Field, Porous Plate Capillary Pressure, Electrical Properties and Relative Permeability Curves (Steady State) showed correlation with the defined rock types and in turn allowed for determination of the gas accumulation potential of the area. Finally, rock and fluid (dry gas) properties have been used to build a Single Well radial model to design initial well tests (DST), and predict production performance from each interval (selective tests). The simulation model represents the lateral and vertical heterogeneity related to the geological environment (Turbidites). The final results have defined the flow and shut-in times during tests to optimize budget. INTRODUCTION The study area is located in the Sinú basin of the Colombian Caribbean Sea, near the Northwestern region of Colombia (See Figure 1 ). In the area, 3 wells have been drilled and the potential for dry gas accumulation (C1 > 95%) was recognized from bottom samples carried out in wells W-1 and W-2. Two of the wells (W-1 and W-2) were cored in the stratigraphic section of interest (a combine 162 meters for both wells) in order to perform a complete petrophysical and mineralogical characterization, and thus evaluate the potential of accumulation and production gas in the area.

The Mundu Formation has been proven to be a prolific reservoir in the Madura Strait area of the East Java Basin. It is a Pliocene bioclastic limestone mainly composed of foraminiferal of planktonic genus Globigerina interpreted to have been deposited in moderately deep water (150 to 250 m), possibly on a detached platform (Triyana et al., 2007). The porosity of the Mundu Formation is typically dominated by intraparticle porosity where the best intervals have less lime mud and less clay association. An integrated workflow has been adopted to decipher high-resolution facies sequences using microresistivity images and nuclear magnetic resonance (NMR) derived techniques. Firstly, microresistivity images were analysed and transformed into calibrated porosity images using a technique to calibrate the acquired image data to image porosity by using various filtering techniques. The image data is averaged over a moving window, and a transform is constructed, which calibrates the average image data to porosity. This transform is then applied to the "pixel-by-pixel" image data, and a moving adjustment for bias is made. The second step is to analyse the T 1 and T 2 relaxations from the nuclear magnetic response. Both relaxations are sensitive to the pore surface-to-volume ratio. Lithologies exhibit several pore sizes, and the analysis of raw NMR data results in a distribution of relaxation times reflecting the contributions of each pore size. In the present study, the Classi-PHI model was designed to work with T 2 relaxation distributions. Linking relaxation time to pore radius suggests a discrete correspondence between pore size and relaxation time. The model used a methodology that allows portions of signal from a pore-size group to spill across the discrete boundaries. Thus, the pore-size quantification in Classi-PHI takes on a fuzziness near the discrete relaxation time cutoffs corresponding to pore radii breakover points. High-resolution integrated facies were analysed and classified in accordance with their possible mode of occurrence. This, in turn, indicated the possible paleo-environment of the deposition. This is extremely helpful for locating high pore-perm layers of grainstone in overall thinly bedded sequences of packstone and wackestone and subsequently sheds light upon the ambiguities observed in mobility testing across the same lithocolumn.

We observe a set of significant petrophysical changes at a critical stage of organic maturation in samples measured from an organic-rich (up to ∼18 wt% TOC) source rock. The observations are from the same Late Cretaceous, Ghareb-Mishash formation in Israel that display various stages of organic maturation. The Ghareb-Mishash samples were cored from three wells from two basins at depths from ∼300 to 1200 m. Among the observed changes at this critical stage of organic maturation: electrical resistivity increases sharply and displays non-Archie behavior; permeability decreases sharply with a steeper Klinkenberg-corrected gas permeability-porosity relationship; and NMR T 2 distributions display two well-separated peaks rather than one. To explain these observations, we analyze the maturity of the organic-rich chalk using Rock-Eval and LECO analysis of the samples before and after bitumen extraction to determine bitumen content and maturity (measured as Tmax). We find that at a critical Tmax for this Type-IIS kerogen (S/C>0.04), the rate of bitumen and light hydrocarbon generation increases sharply. SEM studies show that the chalk contains micritic pores as well as intergranular macropores, and the macropores contain the organic matter. The occurrence of the double peak in the NMR data indicates the shift from strong to weak diffusional coupling and thus the isolation of the micritic pore space from the macropore space for both molecular diffusion and fluid flow. In this dual-porosity Type-IIS self-sourcing chalk, enough bitumen is generated during maturation so that the macropore surfaces become more oil-wet and bitumen blocks the entrances to the micritic pore space. This interpretation of bitumen and light hydrocarbons in the macropore system represents a consistent understanding of the different petrophysical responses, with important exploration and production implications. INTRODUCTION The exploration of the unconventional resources in the Late Cretaceous Ghareb-Mishash formation in the Shefela and Golan basins in Israel has encouraged research to assess the potential economic viability of these fields. In the Shefela basin, the organic matter is immature because of shallow burial, whereas in the Golan, the more deeply buried organic matter is more mature (Gvirtzman et al. 1989, Almogi-Labin et al. 1993, Ashckenazi-Polivoda et al. 2011, Burg and Gersman 2016, Meilijson et al. 2018, Rosenberg et al. 2020). The petrophysical differences between the two basins due to burial and organic-maturation are obvious, but the interpretation of the data for the early-stage mature, organic-rich chalk has not been straightforward.

The main petrophysical challenges in carbonate reservoirs are often to define meaningful rock types, then to establish robust permeability and saturation models for these rock types, as well as to develop a realistic estimation of irreducible water saturation ( S wirr ). Realistic S wirr estimation is important for predicting production behavior (expected development of water cut) and thus ultimately for planning the future development scheme of a discovery. In this study, we present the 2014 Alta discovery, located in the south-western Barents Sea. More than 50% of the expected hydrocarbon resources reside within complex carbonate reservoirs of Permo-Carboniferous age that display highly variable rock properties. Initial screening revealed that primary rock textures and pore geometries were for a large part overprinted by diagenetic processes. Hence, a better control on the reservoir's diagenetic evolution will be needed to apply a full-scale rock typing workflow. In the meantime, it was decided to proceed with a simplified reservoir characterization approach based on the main stratigraphic building blocks. Sufficient core coverage allowed for using permeability measurements on core samples as direct input to a 3D reservoir model. A customized core analysis program, using whole core samples, was designed to characterize the effect of large-scale vuggy pores. For modelling water saturation, a workflow based on Thomeer hyperbola was developed that describes Mercury Injection Capillary Pressure (MICP) curves. The results adequately specify the saturation in all the stratigraphic building blocks. However, saturation uncertainty in the reservoir is high due to a highly variable cementation factor (m), unknown wettability and the presence of residual oil below the current Free Water Level (FWL). The Alta structure has been, and still is, leaking gas, causing the FWL to rise over time. To address the otherwise underestimated volumes in the transition zone above the current FWL, a deeper pseudo-FWL was created and used as input to the saturation height function. Despite log-based water saturation (Archie) and core measurements (Dean Stark) indicating more than 80% water saturation for less permeable reservoir rocks within the oil leg, production tests did not produce water at normal rates. This clearly demonstrated the need to distinguish "nonproductive" pore systems (with capillary-bound fluids; in this case water) from pore systems contributing to production ("free" fluids). A large MICP dataset confirmed that most reservoir rocks exhibit a mix of different pore types and pore throat diameters. To model this accurately, porosity partitioning in non-productive micro-porosity and free-porosity using the NMR logs was performed. Calibrating appropriate T2-cutoffs by matching core MICP to NMR logs in these heterogeneous rocks is seriously hampered by the large difference in sample size. Applying both MICP and NMR measurements to a subset of core plugs helped resolving this challenge. Comparing the corresponding free porosity to total porosity revealed near-linear relationships for different reservoir rocks. For irreducible water saturation ( S wirr ), S wbound is calculated using the NMR-based free porosity. S wbound is considered to be a close approximation of S wirr . The resulting full-field simulation showed a significantly improved match between model output and recorded well test data.

Cased hole logging for formation evaluation and input to determine the re-development potential of an oil producer with a challenging production history was conducted. This included an intelligent assessment of formation gas pressure through casing, which was later confirmed by perforating. The target reservoirs are Triassic sandstones drilled as a gas exploration prospect. Based on open hole log data the prospect appeared to be oil bearing. The well has been producing oil for several years and is now a candidate for a gas cap blow down. The presence of heterogeneous layers with varied rock quality and producibility indexes coupled to complexity in fluids distribution and zonal isolation issues complicates the development process and ability to optimize recovery from any contributing level. Recently a new generation cased hole formation evaluation tool that provides multiple independent formation property measurements was deployed to enhance knowledge of the formation parameters while describing the current gas and oil volumes. Sigma, neutron porosity, fast-neutron cross section (FNXS), and elemental concentrations including total organic carbon from inelastic and capture spectroscopy were simultaneously recorded. Because the well is highly deviated in the zones of interest, the tool was efficiently conveyed on wireline using tractor technology. The evaluation techniques used to study this rich set of data reveal several information that are essential to the petrophysicists and geologists, and to the reservoir and production engineers. A multi-mineral solver analysis guided by the prior knowledge of the rocks using cores from offset wells was conducted to quantify the porosity and gas/oil contact levels, while giving access to detailed knowledge of matrix and rock composition for refining the reservoir models. Additionally, a novel method to determine gas pressure at the current time from the cased hole log measurements was applied, to support reservoir management. The highly sensitive sigma, neutron porosity, and FNXS gas properties can be parameterized as a function of pressure and temperature if the formation and fluid properties are known. This is a well-established principle that can finally be applied independently and directly to multiple measurements. The computations are done independently and checked against each other for consistency and to support optimal parameter setting, in an iterative manner. This is particularly important in this scenario where the complexity of the wellbore environment and history of the well could have complicated the ability to achieve enough precision on the estimated pressures when coming from a single method or if modeling is required. The log results, with validation, and implications for the well re-development are presented together with a general discussion on the methodology and applicability based on this well experience. The importance of meticulous job preparation, pre-job modelling and data quality control is also highlighted. The information is key to defining the future well development management strategy and clarify the role that cased hole logging can play as part of the complete well evaluation process.

Marine carbonate reservoir formation evaluation is typically not concerned about the presence of clays, provided that the deposition of good quality carbonate platform facies is normally limited to clear waters. Conversely, the South Atlantic lacustrine Pre-Salt deposits contain abundant magnesian clays (e.g., kerolite, stevensite, mixed-layer kerolite-stevensite, sepiolite, and saponite), associated to the bioclastic and chemical carbonate reservoirs. These clay minerals precipitated under extreme alkaline environmental conditions, and are peculiar in terms of composition (e.g. kerolite - (Ca 0,03 Sr 0,02 Na 0,01 ) (Mg 2,88 Al 0,01 ) Si 4.02 O 10 (OH) 2 .nH 2 O) and occurrence, exhibiting laminated, massive, ooidal, peloidal, and coating habits. They are very distinct from the conventional detrital or common diagenetic clays that occur in siliciclastic reservoirs, requiring different petrophysical interpretation models. For instance, the conventional approach for clay content evaluation using gamma rays is not adequate, considering that Mg-clays are poor in radioactive elements such as potassium. Moreover, the density versus neutron cross-plot does not display a clear contrast pattern between clean reservoirs and clay-rich rocks. On the other hand, NMR logs exhibit a highly distinctive clay bound water relaxation time (<3ms) in Mg-clays-rich intervals, similar to a shale pattern, even though the proportion of such clays in relation to carbonates (calcite and dolomite) is rarely higher than 30%. In addition, Mg-clays strongly affect sonic logs, decreasing both shear and compressional velocities, which can be useful to identify them in cross-plots of density versus interval transit time. Mg-clays are quite unstable minerals, what resulted in their dissolution and/or replacement by other minerals. A reasonable amount of porosity within Pre-Salt reservoirs has been interpreted as secondary, formed by dissolution of these clays. They are absent in many wells. However, in some areas, Mg-clays-rich carbonates may be thicker than 200 meters. The intervals with abundant preserved Mg-clays are not considered reservoirs, as, despite their fair porosity, they have very low permeability (<.1mD). In contrast, preserved Mg-clays are scarce in the reservoir facies, indicating that either Mg-clays were not deposited in those areas and/or periods, or that they were dissolved soon after deposition, due to changes in the chemistry of the lacustrine fluids, or later during burial diagenesis. Therefore, the understanding, evaluation and prediction of Mg-clays occurrence are of paramount importance for the petrophysical interpretation in the exploration and development of Pre-Salt reservoirs. INTRODUCTION The presence of clays in marine carbonate reservoirs typically is not a problem, considering that environments favorable for the generation and accumulation of carbonate sediments are usually clear waters with low solid suspension content (James and Jones, 2016). Additionally, the authigenesis of clay minerals on those rocks is limited, since the interaction of interstitial waters with carbonates normally does not provide ions ( e.g. Al and SiO 2 ) for their formation. However, continental carbonates may be composed of complex mineral associations, which precipitation is controlled by local environmental conditions (Renaut et al., 1986; Buchheim and Awramik, 2013). This is the case of the extensive South Atlantic Pre-Salt sag deposits, which precipitated directly from lacustrine waters in association with Mg-clay minerals and silica under extreme alkaline environmental conditions (Wright and Barnett, 2015). The underlying rift reservoirs are composed of bioclastic deposits (Carvalho et al., 2000), which are also associated to Mg-clays in complex patterns (Armelenti et al., 2016; Goldberg et al., 2017).

Petrophysical characterization includes the evaluation and integration of data from multi-disciplinary well logging measurements. Because of different depths of investigation and multiple physics, each measurement is sensitive to different reservoir properties, including fluid and rock properties. During the well construction, the mud filtrate can invade the near-wellbore region and replace the formation fluids. This may impact density, resistivity, and other measurements. As a result, we may incorrectly estimate porosity and saturation, and therefore underestimate or overestimate reserves. To correct for actual fluid saturation in the pore space, we need to account for mud filtrate properties and the invasion profile. We present here a methodology for using a data and physics-driven method to quantify near-wellbore water mud invasion and to correct the final hydrocarbon volume estimation. Oil and gas reservoirs in Brazil present an average hydrocarbon recovery factor of approximately 21% compared to the world recovery factor of 35%, see Oddone (2018), and for some fields, the biggest challenge in production is associated with extracting the hydrocarbon in rocks that might vary from mixed-wet to strongly oil-wet and that have highly heterogeneity associated to pore connectivity. For that reason, there is an increasing interest in improving the recovery factor and as part of this challenge increasing the understanding of the properties that influence fluid flow including wettability and the connectivity in the pore network. Studying the near-wellbore region with the integration of logs and cores provides an opportunity of improving knowledge about in situ fluid flow and enhancing the estimation of residual oil, better understanding the pore network system and permeability, all of which are important parameters for reservoir characterization and simulation. For water-based mud wells, resistivity and permittivity are sensitive to water saturation variation along with DOI increase and can be acquired with dielectric and resistivity logging tools, which present sensitivity varying from 1 inch to 50 inches away from the borehole wall, information that is the core to extract the radial profile using the methodology. Resistivity and dielectric logs combined with petrophysical properties and core measurements provide the inputs to derive a calibrated water-based mud invasion profile around the borehole. This radial profile of hydrocarbon saturation can be used to correct the traditional petrophysical estimation, improve the final hydrocarbon estimation and provide an estimation of the minimum movable hydrocarbon fraction of the reservoir. By using a data-driven model based on neural network and an extensive training dataset from physics models we built a fast neural network (NN) model that can generate fast and accurate estimations for reservoir analysis. To generate our proxy model, we developed a near well reservoir model in an industry reference reservoir simulator to generate an extensive database of scenarios that could physically represent the saturation changes by mud invasion. A Neural Network was trained in this dataset and was exposed to both unknown synthetic data and well data. The trained NN was able to reproduce the results for predicting the invasion and saturation profile from the reservoir simulator with more than 99% accuracy for all depth of investigation. Additionally, an integrated petrophysical interpretation estimation requires the mud invasion to be calculated several times for each data point on a well, and this task can only be achieved at a reasonable computational cost using the data-driven model, given that the computing for the data-driven model is less than 1% of the same configuration of the physics simulation. Finally, we applied the machine learning proxy model to a complex carbonate well drilled with water base mud. The results showed a good correlation with the resistivity channels from logging measurements for near well and far-field properties and the inverted depth of invasion, as a result of the radial saturation simulation, there is a reduced bias on porosity estimation when compared with a naïve estimation without considering the fluid invasion in density measurement.

Many methods of calculating water saturation require knowing the chloride concentration in formation water. The chlorides have a strong effect on the properties of water, and they impact saturation estimates that are based on resistivity, dielectric dispersion, or thermal neutron absorption cross section. In this work, we introduce a new, direct, quantitative measurement of formation chlorine from nuclear spectroscopy, which enables a continuous log of formation water salinity within a limited radial depth. Neutron-capture spectroscopy is sensitive to the presence of chlorine and would be a natural fit for measuring chlorine concentration, if not for the fact that the spectrum contains chlorine gamma rays from both the formation and borehole. The borehole chlorine background can be large and is highly variable from well to well and along depth. Historical efforts to derive water salinity from spectroscopy have relied on ratios of chlorine and hydrogen, which suffer from the presence of the borehole yield and from the hydrogen signal of hydrocarbons. A more reliable basis for salinity interpretation is provided by the direct use of chlorine, once its formation signal has been isolated. We partition the borehole and formation components of chlorine via two unique spectral standards. The contrast between the two standards arises from gamma rays undergoing different amounts of scattering based on their point of origin. The shape of the borehole chlorine standard must be dynamically adjusted along well depth to account for environmentally dependent gamma ray scattering. We represent the borehole standard as a linear combination of two components, with a ratio that is a continuously variable function of borehole size, borehole fluid density, and neutron transport in the formation. The algorithm is derived from a combination of 115 laboratory measurements and 2435 simulated measurements. The modeled database spans a diverse range of lithology, porosity, borehole size, and fluids, and is used to validate the treatment of borehole chlorine. The formation standard describes the remaining chlorine signal, and its yield is readily converted into a log of formation chlorine concentration. The chlorine concentration is useful for multiple petrophysical workflows. In combination with total porosity, chlorine concentration sets a minimum value for water salinity. Adding an organic carbon measurement enables the simultaneous estimation of water volume and water salinity. Chlorine concentration can also be combined with a selected water salinity to compute an apparent water volume for comparison with other methods. Finally, chlorine concentration enables calculation of a maximum expected Sigma, which can be compared with the bulk Sigma log to identify excess thermal absorbers in the matrix. A potential limitation of the measurement is its radial depth of investigation (DOI), which is limited to 8 to 10 in. for 90% of the signal. The chlorine concentration is sensitive to filtrate or connate water, depending on formation permeability and invading fluids. We first present the technique to measure formation chlorine, supported by modeling, laboratory data, and core-log comparisons. We then propose workflows to interpret the formation chlorine concentration in terms of water salinity.

Problem . Porosity and relaxation time distributions are the primary outputs of all downhole nuclear magnetic resonance (NMR) tools. Portions of the distributions provide valuable information, i.e., bound and free-fluid volumes, moveable fluid identification, and the estimation of oil viscosity within heavy oil or tar formations. Porosity measured by NMR is subject to environmental influences, such as temperature, local magnetic field, mud type, and, in particular, tool motion. Motion causes a plethora of distortions to the data and affects all low-gradient nuclear magnetic resonance logging tools. Lateral motion distorts the echo train, at times manifesting as erratic noise or a complete loss of cohesion. Axial motion, on the other hand, can cause loss of magnetization or severe over-polarization. Tool motion also affects relaxation time distributions. Methods for axial motion artifact-free data exist, but real-time telemetry (mud pulse) bandwidth limitations have made practical implementation challenging. The drilling environment also introduces challenges to real-time processing. To deliver porosity and distributions free from motion artifacts requires knowledge of the motion. Axial motion can be easily calculated at surface; however, processing the data from the time domain to a relaxation time domain—a process referred to as inversion—at the surface for acceptable accuracy requires more echoes than is feasible for mud-pulse transmission. To address both the requirement for surface data processing and the limits on data transmission, we introduce a split inversion in detail. Methodology . The inversion is split into two parts. A first inversion is performed where the bulk of the information is processed downhole, the data is reconstructed, and then sent uphole. The reconstruction focuses on the primary points of interest for the measurement, such as amplitudes for a T 1 sequence or sub-sample echoes for a T 2 echo train. This smaller set of data, which retains the signal-to-noise ratio of the full dataset, effectively compresses the data and makes it easier for transmission. A second inversion, performed at the surface, accounts for the rate of penetration. This second inversion uses documented methods for motion-inclusive inversion or motion correcting the data prior to inversion. The motion-inclusive inversions demonstrated in this paper use a kernel with motion information to obtain porosity and distribution that are free from motion artifacts. Results . This paper demonstrates the methodology for using the split inversion, surface rate-of-penetration (ROP) information, and computational modeling for motion-inclusive inversion to enable the delivery of reliable NMR data. The method is applied to an example synthetic log and lab-simulated log in which the porosity is known. Correct porosity and distributions are obtained for the lab data with the split inversion and compared to the real-time answer that would be delivered without the ability to rectify the over-polarization observed in the data. The results presented are applicable to the axial motion, which can be calculated at the surface using the time-depth log, unlike lateral motion. The split inversion method also has applications as a data-compression method for any NMR tool.