High-resolution wellbore measurements such as microresistivity images are routinely used to define structural information such as formation dip and azimuth to compare with low-resolution seismic migration. The scale differences between microresistivity images and seismic images range from millimeters to hundreds of meters, which is then compared with vertical seismic profile (VSP) data at tens of meters of scale and sonic velocities at less than 0.5 m scale. Sonic imaging techniques from both monopole and dipole sources can be further used to extend the volume of investigation around the wellbore and define true dip and azimuth of the formation extending 25–30 m into the reservoir. When using the dipole source for sonic imaging and recording the single-receiver sensor data, we observe polarized shear reflections that present not just the linear and sinusoidal moveouts evident as a function of source-receiver offset and nominal receiver azimuth, but also a significant polarity signature that is a function of the reflected wave’s particle motion direction. A variation of 3D slowness time coherence (STC) is presented that correctly processes these polarized shear reflections to determine the dip and azimuth of the reflector. We then demonstrate how this new 3D STC processing is integrated into an automated processing that locates and characterizes the reflected arrivals in the filtered waveform measurements and then maps the corresponding reflectors in 3D along the well track. Of note is how the automated processing with the new 3D STC variation resolves the 180° ambiguity of the reflected dipole signal noted by previous authors. This is particularly important when imaging or mapping formation structure in a highly deviated wellbore, because the single-sensor data can image both above and below the wellbore, compared with conventional modal decomposed dipole waveforms, for which distinguishing top from bottom is ambiguous. A case study is presented from offshore Abu Dhabi, in which an interbedded carbonate reservoir is examined with various acoustics measurements and microresistivity images. A detailed structural analysis is conducted using a walkabove VSP whereby the migrated image below the wellbore is used to compare with the sonic imaging results from azimuthal monopole and dipole sources. Migration images from the dipole shear clearly show subseismic-scale layers in comparison with the VSP migration. Structural dip and azimuth of these subseismic features provide detail 30 m into the reservoir.

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.

In the current business environment, operators are increasingly striving to reduce logging expense when possible, while maintaining safety of the drilling operations. Mudlogging has been remarkably successful through the oil industry downturn due to the value of information derived from the analysis as well as the relatively low cost. Information about the lithology and fluid content of the borehole during drilling is important for drilling optimization and qualitative petrophysical assessment. This paper takes mudlogs a step further to quantify net pay and estimate reserves in low permeability reservoirs where traditional log analysis is challenging. Methods will be described for estimating gas-in-mud based on characterized gas measurement systems and obtain bulk volume of gas per volume of rock drilled. Corrections are discussed for mud gas systems based on their mechanical operating parameters of mud flow into the gas extractor, gas sample suction rate out of the gas extractor, recirculated gas, and estimated gas extraction efficiencies. Applying these corrections yields normalized bulk gas volume and gas-oil ratio which is calibrated with the petrophysical assessment from wireline logs and PVT samples. Finally, correlations between bulk hydrocarbon volume and permeability are used to estimate volumetrics. Case studies presented show that the calibrated mudlogs can be used for quantitative assessment of bulk volume of hydrocarbons in high-angle/horizontal-wells where conveying wireline logs might be challenging. Pay flags computed from the mudlog interpretation can be used to guide completion decisions. Additionally, GOR estimates derived from mudlogs can be used for fluid typing and optimizing the fluid sampling program in deepwater development wells. Results presented clearly show that mudlogs can provide continuous, real-time, and quantitative petrophysical assessments. INTRODUCTION Mudlogs continue to be the most important petrophysical data source available before wireline and logging while drilling (LWD) runs. Continuous gas monitoring service involves extraction of gases from the returning mud stream and analysis of volatile hydrocarbons. Commonly, the gas chromatography analysis is logged in real-time at drill depth and plotted with rate of penetration (ROP) and cuttings sample log (Whittaker, 1991). Therefore, the mudlog provides a unique dataset integrating drilling, geology, and petrophysics. However, the data is subject to uncontrolled variables in measurement technology as well as the dynamic borehole environment (Kyllingstad et al., 1993).

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.

Full geological interpretation is now possible from logging-while-drilling (LWD) in oil-based mud following the advent of high-resolution acoustic borehole imaging technology. The new service provides acoustic amplitude images of the borehole wall, in addition to borehole shape in a resolution that greatly surpasses previous capabilities in oil-based mud. The measurements include acoustic amplitude (this response is a mixture of petrophysical properties and borehole shape) and acoustic travel-time (showing the stand-off of the borehole wall from the sensor). From the travel-time measurement, we calculate the borehole profile which is shown in a tube plot and is used to project borehole shape properties. In water-based mud, the acoustic imaging tool can be run in combination with the existing high-resolution electrical imager. This combination is particularly useful for characterizing fractures with the dual resistivity and acoustic properties for a more confident interpretation. We show examples from wells with a range of geological complexity, including fractures, faults, geomechanical features, sedimentological variation and changes in borehole shape. Contrast between lithologies and structural features and the background is similar to that seen in electrical measurements in the same environments. Fractures with a high acoustic amplitude response show a marked contrast with the background lithology. In many cases, they reveal the processes of formation including cataclasis, intersections, age-determining relationships and impact on reservoir connectivity. The inclusion of borehole shape with the acoustic amplitude image gives a new value to fault interpretation, where post-drilling stress release can be interpreted from the shape of the borehole surrounding a fault. In this example, micro-slippage along a fault can be seen directly in the protrusion into the borehole of one side of the fault. Amplitude images are detailed enough to allow full image facies characterization similar to that possible from wireline image equivalents, but with the benefit of measurement of the formation before the build-up of mudcake. We show examples in clastic and carbonate lithologies that include primary sedimentary structures, secondary remobilization processes and diagenetic overprints. Sedimentary detail in coal beds is unprecedented, including bedding and variation in mineralogical components. Applications based on borehole shape are shown, including geomechanical features, borehole stability, time-lapse logging and hazard mitigation. INTRODUCTION Borehole image logs have been evolving continually for several decades. This has been marked by advances in measurement physics, measurement sampling density, sensor resolution and changes in acquisition mode, such as wireline/LWD and acquisition in water-based mud/oil-based mud (Pöppelreiter et al. 2010, Ritter et al. 2005). Within the realm of the LWD acquisition mode, there has also been a continual evolution, culminating with the recent introduction of high-resolution acoustic measurements that now rival the quality of existing wireline services.

As oil and gas exploration and production extends to deeper buried reservoirs, challenges such as lower porosities and Ultra High Temperature have been encountered. Several reservoirs in the Asian region, the North Malay basins in the joint development area between Thailand and Malaysia, and the Baiyun Sag and Qiong Dongnan basin in offshore China are considered to have the highest known temperature gradients due to their geological depositional system and hydrocarbon charging mechanism. More than fifty percent of wells drilled in these areas have temperatures close to/or higher than 170 degC, and some reach above 200 degC. In number a of projects in these areas, the logging requires tools that can withstand up to 230 degC. Traditionally, Wireline Formation Testers (FT) with fixed rate and volume pre-test and old sampling technique using a dumping chamber (i.e. without pumping capability) had been the standard formation tester when temperatures reached 400degF (204 degC) and higher. The tools were not flasked and therefore, the temperature transient affected the quality and accuracy of pressure data 1,2 . Also, in such harsh environment, it is very difficult and time consuming to go back to a good mobility station for sampling after a pressure measurement, due to reservoir heterogeneity and depth error. This paper discusses a project for a new slim hole ultrahigh temperature Wireline Formation Tester designed to obtain both pressure profiles and perform downhole Pressure Volume Temperature (PVT) fluid sampling with pump-out capability and downhole fluid sensors such as viscosity, density and resistivity in extreme HT environments. In addition, this slim hole ultrahigh temperature tool dimension has more clearance between the tool and formation, and therefore, less chance of having this tool get stuck during slim hole logging. The tool was first deployed in the North Malay Basin and since early 2018, five development wells were logged where a total of 76 pre-tests, four pump-out and ten fluid sampling stations were conducted. The main objectives for this FT tool were to obtain formation pressure, identify reservoir fluid and quantitative CO 2 measurements zone by zone. The results will be discussed operationally and technically, in terms of data quality and accuracy and compared with on-site surface analysis. In addition, this tool improves significantly operationally compared to the previous tools and with some operators having mixed perceptions on running Wireline FT tool with bigger ODs, especially drilling departments. Having this new slim hole tool with its smaller OD increases their confidence level in running it. For Deepwater Offshore China, an operator has been facing challenges to explore a brand-new block such as pore pressure distributions profile, reservoir quality, and constrained logging period. The main objectives for the extreme FT are to obtain the formation pressure for drilling purpose, to understand reservoir potential to optimize the perforation interval for Drill Stem Test, and to narrow logging operation time window due to seasonal weather. This new ultra-high slim hole was therefore proposed to log in this challenging environment. This field example shows a significantly improved pre-test and sampling capability in the lower mobility ranges, which some previous generations of formation testers had struggled with in the past, in one run and without sacrificing testing efficiency. The effective time for valid pretest can be achieved even in the range of mobility 0.01 mD/cp, high pressure of >11000 psi, and high temperature of >180 degC. This paper discusses pre-job planning and actual job execution results in both locations. The challenges of logging and lesson learned are addressed. This is the first attempt in evaluating reservoirs in the deeper and HT sections to properly understand reservoir fluids.

Accurate prediction of formation stresses that could potentially cause fracturing or formation damage in the near-wellbore area during drilling is clearly important. Additionally, developing a geomechanical model using stress prediction is important to selection of "sweet spots" and locations for well fracturing. Unfortunately, models used to make continuous depth-based stress predictions involve many parameters derived from laboratory testing, fracture injection tests, and the actual fracturing of a well—all contributing to prediction uncertainty. It is generally recognized that the most difficult component of stress to predict is maximum horizontal stress. This work describes the following three approaches to estimating maximum horizontal stress—(1) from borehole breakout and borehole wall fractures, (2) from anisotropic poroelastic stress equations, and (3) predicting an upper bound from a stress polygon. It is shown how stress prediction and interpretation can be improved by simultaneously applying each approach, depth based, using wellbore acoustic and borehole image data calibrated to laboratory and field measurements. The three methods applied require knowledge (prediction) of the minimum horizontal stress before predicting the maximum horizontal stress. Thus, the standard anisotropic stress equation for minimum horizontal stress is used and a discussion for obtaining calibration parameters is presented. A workflow is developed for using the available ancillary data for calibration. The results provide depthbased predictions of overburden and pore pressure, as well as minimum and maximum horizontal stress from which a fracture initiation pressure can be predicted. Additionally, a depth-based fault regime (either normal, reverse, or strike slip) is computed from the stresses. Finally, results are presented from log and core data of an unconventional reservoir well. INTRODUCTION One needs only four parameters to fully define the state of stress at depth: three principal stress magnitudes; S v , the vertical stress corresponding to the weight of the overburden; S Hmax , the maximum principal horizontal stress; and S hmin , the minimum principal horizontal stress, and one stress orientation, usually the azimuth of the maximum horizontal stress, S Hmax .

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.

Cement bond evaluation is a critical step in the early-life stages of newly drilled wells since it rules the way for obtaining useful information about wellbore integrity. Conventionally, this is carried out by means of a detailed interpretation of cased-hole sonic and ultrasonic log data. However, this standard approach can be highly time-consuming and challenging in long completion sections and when complex scenarios have to be handled in operative time. In this respect, oil companies have stored huge datasets for their wells, with quality-checked cased-hole acoustic logs and associated interpretations in terms of wellbore integrity. This paper deals with a novel, probabilistic data analytics approach aimed at obtaining a fast and robust cement bond facies classification. The latter is deemed able to automatically provide an exhaustive quantitative cement placement evaluation, hence avoiding time-consuming processes and possible subjectivity issues. The implemented methodology takes advantage of the Multi-Resolution Graph-based Clustering (MRGC) algorithm that gathers its knowledge by recognizing patterns in sonic and ultrasonic logs/maps from dozens of wells, including more than 500K meters of logged intervals. This allows the system to learn through experience how the log measurements are related to the common cement bond scenarios (e.g. good, partial, poor cementation, dry or wet microannulus, free pipe). The MRGC is then integrated in a Bayesian framework to obtain the probability of the cement bond facies, the most probable scenarios, and the associated uncertainty by means of entropy computation. In detail, an automated screening can be performed in newly drilled wells to detect possible problems of hydraulic sealing. The potentialities of the discussed method are demonstrated by real case applications consisting of cement log data collected from several blind-test wells. First, the probabilistic approach is used to predict the cement bond scenarios together with the uncertainties of their classification. Then, an unbiased evaluation of the results is performed. The successful outcomes coming from the final step of the workflow show how, with a statistically representative and good quality dataset, data analytics can efficiently mimic high-skill expert work in harsh circumstances and within a time-efficient template. In fact, this data-driven methodology takes few seconds to provide an exhaustive interpretation against, at least, one day with the conventional one.

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.

The hydrostatic pressure of the mud column in the wellbore is usually greater than the formation pressure causing mud filtrate to invade the formation in the vicinity of the wellbore. When oil-based mud (OBM) is used, unlike water-based mud (WBM), OBM is miscible with the formation fluid and alters its fluid properties and phase behavior. To be able to sufficiently correct for the contamination in the fluid sample, it is required that the contamination level be sufficiently low. This means that the engineer will continue to pump the contaminated fluid around the probe area until it is sufficiently clean. It is important to be able to measure the contamination level of the reservoir fluid as accurately as possible in real time before taking the sample, as taking additional downhole samples after the well is completed may be difficult if previous samples are not useable. Cleanup time depends on multiple parameters, including formation permeability, fluid viscosity, depth of invasion, and wellbore mud column overbalance pressure. Most current methods for predicting contamination rely on curve fitting to a single property such as fluid density, gas content, and color. Curve fitting relies on the assumption that when the properties being monitored do not change significantly as the pumping continues, the contamination level is low. However, this can also be because of a steady-state effect even at high contamination levels. Also, contamination value from curve fitting method is sensitive to data selection and also depends on the endmember filtrate and formation fluid properties which cannot measured directly either downhole or in the laboratory. In this work, we present a technique for predicting contamination using pumpout density and volume and formation properties such as drawdown mobility, overbalance, formation pressure, and drawdown pressure. By combining multiple parameters such as fluid density, drawdown mobility, formation pressure, overbalance, and drawdown pressures, predicted contamination values are better constrained. Moreover, this technique does not depend on end member properties. The technique is based on constraining pumpout data with formation properties from pressure testing data. In this technique, a large dataset of pump-out volume, density, and formation properties data acquired from wells from different regions of the world are used to develop a predictive model using a machine learning approach. The pumpout density is represented as optimized parameters of an inverse power law model. The estimated contamination value at the endpoint in the field case examples presented in this paper is fairly close the reported laboratory value of the sample taken at the end of each pumpout.

Electromagnetic (EM) inversion processing of ultradeep resistivity data has advanced from one-dimensional (1D) to three-dimensional (3D). These advances have helped improve the quality of inversion results and provided additional reservoir information. The large depth of investigation of ultra-deep LWD azimuthal EM tools (100 to 225 ft) means that distant boundaries might not be detected by any other sensor in the tool string, making it difficult to verify the results. As inversion results represent a model of the subsurface resistivity distribution, and are not a direct measurement, it is important to have high confidence in the results. With the multi-frequency, multi-component data used in 3D inversion, it is possible to directly compare the component data measured by the tool to the modelled component data. If the data shows a good fit across multiple frequencies, this provides confidence in the resultant model. However, as measurement sensitivities decrease with distance, it is possible to create an apparently good match between the measured and modelled component data with a model that is geologically unrealistic. Increased confidence in the results can be achieved when it is possible to verify them independently, such as by mapping a particular zone from multiple wellbores. This paper details results from a tri-lateral well in an injectite reservoir wherein the sand distribution and the associated resistivity distribution were very complex. 1D inversions showed the vertical distribution of the sand, but the results were sometimes distorted by lateral resistivity variations. Ultra-deep azimuthal resistivity images showed the resistivity distribution around the wellbore, but it was 3D inversion of the data that allowed the structures to be resolved clearly. These results can be corroborated by direct comparison with the azimuthal resistivity images, but the position of major sand bodies near the start of the laterals allows a further step to be taken to help increase confidence in the 3D results. The laterals all diverged from the same main bore and remained close together initially in an area containing major sand injectites. 3D inversions from two of the wells overlap and define similarly shaped structures, providing high confidence that the 3D inversion produces a good representation of the sand distribution. The third lateral diverged quickly, but the 3D inversion results from it still showed a major sand unit that could be traced back to the first lateral. In complex geobodies, such as the injectites described, significant lateral variation in the reservoir distribution is expected, which is not captured by 1D inversion. Understanding the shape of these structures and their potential connectivity using 3D inversion provides a major increase in reservoir understanding that is critical to completion design. Independent verification, by overlaying inversion results from adjacent wells, provides an additional proof beyond the verification methods available in a single wellbore.

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 recent demand for green and renewable energy sources has gained significant economic importance in terms of reducing greenhouse gas emissions. Located within a volcanic setting, Indonesia has approximately 40% of the world’s geothermal energy resources, hence the geothermal power market is remarkably huge with a reported installed capacity of 1900 MW in 2018, the second largest globally after the United States. The effort to increase the output of this untapped resource is very encouraging and requires good understanding and evaluation of these complex volcanic reservoirs. This includes the structural evolution in the area and locating sweet spots in the lithocolumn for deciphering the controlling factors that govern the producibility within the field. Well logging measurements, including borehole imaging and acoustic tools, were deployed to investigate the characteristics and patterns in the lithocolumn to identify sweet zones for good reservoir sections. The workflow includes borehole imaging-based applications and structural and fractures characterization. The promising sections are correlated to drilling results to delineate optimum zones and the intrinsic properties of the sweet spots. The structural framework is then correlated with the wells in the same field to understand factors that control the contribution of each zone and the lateral continuity of these reservoirs in regard to the overall geological evolution in the area. The assessment was made employing fracture identification from borehole microresistivity images classified based on their morphology into various classification fractures, with effective fracture types being the primary interest. The dominant strike direction of these fracture sets were observed to be north-southerly with aperture values obtained from resistivity imaging estimated between 1 and 8 mm with a mean of 4 mm. The maximum principal horizontal stress within the study area were observed to be in the northeast-southwest direction based on drilling-induced linear features, which were then correlated to the properties of the fractures contributing to steam production. This work provides insight into factors to identify properties of productive fractures for steam gas reservoir production. Understanding the characteristics of fracture properties and geometry in relation to the geological evolution of the structural framework in this area can be beneficial to identifying infill wells for optimum recovery of renewable sources of energy.

The calculation with the Archie equation of water and oil saturations from electrical resistivity logs in water flushed reservoirs has historically been challenging. Previous publications on experiments conducted at the laboratory have demonstrated that, in waterflooded reservoirs, the imbibition regime impacts the resistivity index and may lead to an Archie saturation exponent "n" different from the SCAL drainage measurements (referring to the "n" hysteresis between drainage and imbibition observed in oil-wet rock samples). While core, log and reservoir techniques can approach the residual oil saturation (SWTT/NMR/core Sor), they are not commonly used in the realms of a deep offshore field development for operational and cost reasons. This paper presents the results of a case study, offshore Africa, from a highly deviated well that intercepts turbiditic sands (high porosity, oil-bearing) irregularly swept by viscosified polymer-water (injected nearby). Thanks to in-situ sampling of the injected fluid, the water saturation was derived from the sigma log (neutron capture cross section) in order to pinpoint the undisturbed zones and then, by comparison with the resistivity saturation equation, estimate the magnitude of change of the "n" parameter in the flushed zones. Beyond the added value of the so-called old sigma log, which uncertainties and limitations will be discussed, the extra-information gained by knowing both the polarity and the magnitude of change of the "n" parameter gives access to an indication of the insitu change of reservoir properties. The polymer additives present in the injected water may be the cause of the deduced electrical hysteresis and can lead to insightful understanding of reservoir behavior in water flooding context. Such results finally lead to a better estimation of the remaining hydrocarbon in place. INTRODUCTION In development context (water injection, EOR…), the reconciliation between resistivity derived oil saturation and other techniques (sigma, C/O, NMR, Dean-Starks) often seems impossible if using the drainage saturation exponent " n ". But appropriate imbibition measurements are often not available. Then, in case of strong drainage-imbibition " n " hysteresis, gross overestimation of the remaining oil saturation may result from resistivity interpretation in waterflooded reservoirs. Through a comparison between the resistivity derived water saturation and the neutron capture (Sigma) saturation, we first demonstrate that results are in reasonable agreement in pay intervals and aquifers, thanks to favorable conditions regarding this type of electrical logging. We then present in a second example crossing water injected areas the expected remaining oil saturation in best sand facies where no " n -hysteresis" is observed. We then show results from an observer well where sand bodies have been early waterflooded by water with polymer and both resistivity and Sigma logs are available but do not reconcile. By comparing water saturations obtained from the two methods, several observations are made on the sweep efficiency at macroscopic scale and the remaining oil saturation as shown by the neutron capture measurement. If reservoir properties have changed during this full drainage-imbibition cycle (polymer injection), it must be addressed with reasonable hypotheses, amongst those the probable difference in rocks wettability between selected examples but also a possible change of pore surface properties (interfacial tension) possibly due to the polymer.

Transient electromagnetic (TEM) or pulsed eddy current (PEC) tools offer salient advantages over conventional continuous-wave remote field eddy current (RFEC) tools for the inspection of multi-barrier well systems. In this paper, we describe a state of the art transient electromagnetic tool that is capable of inspecting up to five concentric barriers. We use this tool to illustrate the working physics of this technology and delineate its features and advantages. The measurements result from a diffusion process, and therefore consist of time-decay curves. These curves exhibit space-time mapping, meaning that the signal at early time is sensitive to proximal barriers while the signal at late time is sensitive to proximal as well as distal barriers. This behavior enables the measurements to independently yield the wall thicknesses and/or metal loss/gain of multiple barriers. This technology yields extremely rich measurements because it uses wide-band excitation. Through diverse modeled examples and field examples, we demonstrate techniques to maximize the information gleaned from these measurements. These techniques can complement automated inversion of measured data and are amenable to the use of machine learning and artificial intelligence methods. Examples and features discussed include pipe collars, discrimination of internal (inner tubular wall) anomalies vs. external (outer tubular wall), tubular eccentricity and buckling or ovality. Key peculiarities often observed in multi-barrier transient electromagnetic measurements are also discussed. INTRODUCTION Well integrity problems place a huge economic burden on oil and gas producers. Corrosion of pipes is a major cause of well integrity problems. There are multiple mechanisms for corrosion, such as electrochemical, chemical, and mechanical. There are several techniques available to mitigate each corrosion mechanism, but it has been impossible to eliminate corrosion altogether. Monitoring of casings and early detection of corrosion and other flaws allow operators to perform timely and economical intervention and/or workover. There is a large spectrum of casing inspection tools that follow diverse measurement principles. Multi-finger calipers can provide a profile of the inner surface of the tubing at good resolution while ultrasonic tools can evaluate both the inner and outer surfaces of the tubing. Magnetic flux leakage tools evaluate the inner and outer surfaces of the first barrier at a very high resolution. To date, only electromagnetic tools are able to evaluate multiple barriers. Being able to independently inspect multiple barriers enables operators to assess the condition of outer barriers without having to cut and pull tubing and/or other inner barriers. This translates to cost savings over the life of the well. Being able to do this offline without a rig translates to cost savings during the plugging and abandonment stage. In this paper, we briefly describe a state of the art transient electromagnetic (TEM) tool that provides quantitative evaluation of up to four barriers, and qualitative assessment of a fifth barrier. The tool comprises three sensors, called the short sensor (SS), medium sensor (MS) and long sensor (LS), respectively. The short sensor provides higher resolution data from the inner barrier, whereas the medium and long sensors provide large depth of investigation to assess the outer barriers. The bulk of this paper focuses on the analysis and interpretation of measurements provided by such an instrument.

Logging measurements in high-angle wells are often complicated by various geometric effects and generally require correction before use in accurate petrophysical evaluation. The geometric effects include, but are not limited to, shoulder beds, proximity to beds that may or may not have been crossed, polarization horns, laminations and non-uniform invasion. A case study demonstrates how log property modeling was applied using a fast and practical workflow to improve petrophysical answers. The wells studied are located in the Norwegian sector of the North Sea and penetrate a sequence of fairly thin sand and shale layers. The well trajectories range from deviated pilot holes through high-angle tangents. In the wells studied, both propagation and laterolog resistivity measurements and their associated wellbore images were acquired as well as azimuthal GR, density and neutron porosity logs. The difference between the laterolog and propagation resistivity measurements highlights the challenges of using the logs directly. A new workflow was used to quickly model the high-angle logs and cross-validate the responses. Although the largest geometrical effects were observed on the resistivity logs, the nuclear measurements were also affected to a lesser degree, and new fast forward models were applied in the same workflow to obtain the GR, density and neutron porosity log properties. The combination of the resistivity responses, and the ability to quickly and efficiently model the logs, provided improved confidence in the derived formation properties which were subsequently used for saturation computations. An example of the effect of thin laminations on high-angle well resistivity logs is shown. In addition, an example of asymmetric fluid invasion caused by gravity segregation of mud filtrate demonstrates how resistivity images aid interpretation in complex geometries. To help visualise these geometries a three-dimensional display tool is applied that allows for more intuitive understanding of the complex azimuthal and radial information provided by multi-depth of investigation resistivity images.

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.

Electromagnetic (EM) resistivity tools measure the electrical properties of downhole formations that are critical in determining the hydrocarbon saturation of a reservoir. In complex and heterogeneous reservoirs, both horizontal and vertical formation resistivities are required to obtain an accurate hydrocarbon saturation. For decades, wireline multi-component induction type measurements have provided reliable determination of formation anisotropy, structural dip, and dip azimuth in wells with any orientation relative to the bedding planes. Logging-while-drilling (LWD) multi-array propagation resistivity tools have also demonstrated similar capability in deviated wells where the relative dip angle is between 45 and 90 degrees. However, measuring anisotropy and dip in wells with low relative dip angle still poses difficulties for LWD propagation resistivity systems because of the simple antenna structures employed. This paper describes the development of a new LWD EM sensor equipped with an innovative, fully triaxial, colocated, tilted antenna structure. The tool, along with a unique processing scheme, enables the determination of horizontal and vertical resistivity as well as the dip angle and the azimuth of the formation while drilling in real time. The co-located sensor design is capable of acquiring multi-component signals that are sensitive to formation anisotropy and structural dip in wells at any orientation. Modeling studies and several field trials have proven that the design concept can detect these formation properties at any arbitrary wellbore deviation. This paper presents test results from the new technology, together with reference measurements from azimuthally compensated LWD and fully triaxial wireline resistivity measurements. Very good comparison is observed in these trials, providing an independent verification of the tool performance. The azimuthal responses of the tool enable measurement of all EM field components, as well as providing 360-degree azimuthal resistivity and geosignals, and allowing a three-dimensional (3D) resistivity mapping technique for real-time decisions at any wellbore deviation. The collocated antennas are further integrated with deep-reading antennas to enhance look-ahead detection ranges for LWD applications.