Abstract This paper presents the implementation of an integrated reservoir modeling approach that tightly connects and integrates different reservoir modeling disciplines. The approach allows the propagation of subsurface reservoir uncertainties across the various modelling domains, from seismic interpretation though to dynamic reservoir simulation and surface facilities modeling. The results achieved by this approach is a geologically consistent ensemble of runs (100 runs or more) that matches observed data and capable of predicting the future field performance under various development scenarios with a higher degree of reliability. Using an ensemble of runs that first honor the geological facies, as initially defined in the prior probability field, and subsequently updated by reservoir production behavior in the post probability field, enables the user to predict future field performance by allowing hydrocarbon recovery probabilities to be calculated, where the impact of subsurface reservoir uncertainties on prediction results and the possible risk in each development decision is estimated. The field studied is located Offshore in Abu Dhabi and has four main, two secondary, and few minor stacked carbonate reservoirs. Available evidence indicates that the field's reservoirs are not in communication and this study focuses on the main and secondary units. The conceptual geological model proposes that all the zones are conformable, with no truncation or pinching, forming a layer cake depositional model in which reservoirs range in thickness, from few feet in thin zones, to tens of feet in thick zones. Over time the field has been affected by different tectonic stress regimes, resulting in complex strike slip faulting, extending vertically across all reservoirs. Quantification of static and dynamic uncertainties together in the applied methodology is improving the team integration and common understanding for the field structural and geomodelling uncertainties and its impact on the dynamic model behavior for different reservoirs. The methodology has been tested where new drilled well data is included at different times and it showed an easy and quick update for the entire workflow from seismic to simulation. The model was calibrated to historical observed data using different geological uncertainties (structural, facies, geomodelling and dynamic uncertainties) which helped to achieve a geologically consistent and reliable models.

Abstract This work investigates the implications of propagating the uncertainty and non-uniqueness of fitting experimental data into the forecast of field implementation of polymer flooding. This research sets the foundation for developing a general framework for modelling and probabilistic performance forecast of chemical flooding. History-matching of polymer coreflood results is posed as a bi-level optimization problem that solves for true waterflood residual oil saturation ( S orw , ∞ ) in the upper level and the relative permeability curves (exponents and endpoints of Corey function) and polymer adsorption parameters in the lower level under two different physical interpretations of the difference between remaining oil saturation after waterflood ( S orw ) and that after polymer flood ( S orp ): Displacement Efficiency Interpretation( S orp ≥ S orw ,∞ ) solely attributes the significant difference between S orw and S orp to improved displacement efficiency. Viscous Fingering Interpretation ( S orp ≤ S orw ,∞ ) considers viscous fingering during waterflood. A range of S orw ,∞ values has been identified for each model based on satisfying cut-off error criteria. For each S orw ,∞ value, dependent parameters are obtained and used in a simplified forecast of field performance in a quarter-five spot well pattern. The inverse of the error within acceptable range was used as probability density function (pdf) for S orw ,∞ which, combined with forecast results, enabled calculating P10, P50, and P90 of S orw ,∞ , recovery factor, and economic metric (i.e. cumulative discounted revenue). The probabilistic forecast results show that the viscous fingering interpretation is more reliable as it generates a forecast with less uncertainty. The impact of model selection and non-uniqueness of fitting lab data on the quantified uncertainty associated with field forecast is demonstrated and the premise of developing a bi-level optimization framework for modeling and probabilistic forecast of chemical flooding processes is supported by the findings of the study. In this work a novel iterative tangents construction technique that considers the inter-dependence between retardation factor due to adsorption and polymer shock saturation is used along with a mechanistic form of fractional flow curves that includes shear-thinning and effective viscous fingering effects. The analytical solution was verified against fine-grid simulation and the two solutions were nearly identical while the former is several orders of magnitude faster enabling extensive investigation of the range of parameters that match the coreflood results and forecast uncertainty under different technical and economic considerations.

Abstract Cement evaluation data acquired in oil and gas wells for confirmation of zonal isolation, channeling in cement behind casing and well integrity. All available technologies for cement evaluations are primarily measurements of acoustic parameters like amplitude of first arrival, full waveform recording of refracted wave, impedance and attenuation or there a combination. Generally, operationsPetrophysicist, petroleum engineer or service providers are responsible for evaluation of cement bond logs and propose remedial jobs if required. This cement bond log interpretation is quite subjective if performed through pure visual interpretation and its accuracy depends on objective of well, work pressure and experience of interpreter. This paper talks about how ADNOC Onshore has leveraged machine learning (ML) for interpretation of various cement bond logs from several service providers. In green fields, cement evaluation is very important in all new wells to ensure good cement quality and zonal isolation and it is also equally important in in brown fields where 1000s of wells were drilled where well integrity issues are of common occurrence. Major challenges in evaluation are inconsistency and human bias in interpretation and as a result, interpretation may vary from one interpreter to the other. Authors have tested different ML techniques (Random Forest Classification & Neural Net) and smart way of data training. Final recommendation is to use nested models instead of single model. In this technique, input measurements and required solutions will be classified and divided into different classes, a separate ML model will be built for each class and combine all the models to get final cement evaluation and recommendations. Final results include data quality flags, cement bond quality, zonal isolation, channeling, micro annuals, areal cement map (if analyzed field wise), anomaly maps (if analyzed data from offset wells at different times), and recommendation. In this project, a simple easy to use user interface has been developed to browse the cement logs and use the trained ML models to predict the cement evaluations with a click of a button. This ML based cement bond evaluation is proved to be very effective and saved 75% of efforts by operational Petrophysicists. The interpretation accuracy has been significantly improved. This method has potential to be used at rig site. These models are very cost effective with, minimum human bias, and improves consistency as well as independent of wells or type of reservoirs. These models are tested across ADNOC Onshore Wells and can be extended to any well irrespective of geographic locations. This paper discusses machine-learning approach, evaluation of various algorithms and testing results for cement evaluation log from various service providers.

Abstract Improving carbonate reservoir prediction, field development and production forecasts, especially in zones lacking data, requires novel reservoir modelling approaches including process-based methods. Classical geostatistic modelling methods alone cannot match this challenge, in particular if subtle stratigraphic architectures or sedimentary and diagenetic geometries, not directly identified as properties with well data, control the reservoir heterogeneity. Stratigraphic forward modelling approaches can provide pertinent information to carbonate reservoir characterization. Integrating carbonate stratigraphic forward models in reservoir modelling workflows faces two sets of challenges: (1) the difficulty to establish high resolution and multi-scales continuous reservoir analogues from outcrops and (2) the development of forward modelling methods adapted to carbonate heterogeneity and calibrated to well data. The ALBION R&D Project dedicated to the Lower Cretaceous rudist-rich carbonate platform meets these two considerable scientific challenges. This workflow builds on previous modelling approaches at basin scale that integrates seismic inversion and forward modelling. This project delivers deterministic high-resolution static models that support the development of process-based modelling solutions. This multidisciplinary approach focuses on the characterization of primary sedimentary and diagenetic overprint that can impact drastically the flow behavior at inter-well scales in similar reservoir units such as the Kharaib and Shuaiba Formations. The SED-RES modelling package developed in house by Total R&D has been tested and calibrated with these high-resolution stratigraphic outcrop models. It allows valid prediction of carbonate facies associations mimicking the spatial distribution mapped along the Urgonian platform transects.

Abstract SNOC embarked on an ambitious project to extract maximum value out of its mature fractured carbonate fields by converting them to underground gas storage facilities. This required the integration of a multitude of new and legacy data including new seismic acquisition, advanced processing and interpretation along with geophysical modelling, PVT, petrophysical and injection/pressure profiles to develop a robust reservoir model for the Moveyeid gas-condensate field. Enabling the operator to use this tool for advanced gas storage simulation predictions and to quantify risk in field development strategy to maximize condensate recovery while minimizing cushion gas volumes. Various seismic frequency cubes and survey vintages were used to delineate the Moveyeid structure and map top Shuaiba formation within the Thamama carbonates of Onshore Sharjah. Legacy wireline logs were reinterpreted using new multi-log workflows, providing inputs for static model development. As a mature field, in production for over 35+ years, cumulative produced volumes were used as an additional control, creating several iterations until achieving a match that honoured the geology. PTA, RFT and PLT were integrated in the model to quantify flow change over time. Advanced imaging revealed a north-South trending normal fault that segmented the field in to two, with all existing wells located on the up-thrown eastern block. Volumetric determination revealed that the eastern block alone was not sufficient to match hydrocarbons produced to date in any static scenario modelled. This was achieved with the inclusion of the western block and an unchanged gas-water contact. The new static model developed is more robust, with an enhanced layering configuration and property arrays that better reflect input data. Benefits were also seen during dynamic simulation where lower property multipliers were applied during history matching. Optimizing the layering and using block parallel computing power enabled the team to considerably reduce runtimes and produce an array of scenarios. The model was put to the test when the gas injection pilot project was commissioned in 2017 with low-pressure injection up to 2020, yielding a well performance accuracy within 5% of actual rates. Optimizing the strategy was essential in reducing planned cushion gas requirements by up to 20% for meeting the production target in the depleted reservoir, improving the project's capex. Utilising a combination of new and legacy data, a depleted gas-condensate carbonate reservoir has been successfully modelled. The model is being used as a tool to formulate the strategy and effectively define the field's suitability for gas storage and enhanced condensate recovery. This paper provides a case study for how these strategies can be implemented in other Middle Eastern analogues where gas storage in mature fields can act as a strategic tool for energy security.

Abstract Jebel Hafit is situated along the border of Oman and the UAE near the city of El Ain, and was subject to numerous studies. It is a key analogue of some of the hydrocarbon producing subsurface structures of the Emirates and an important element for the reconstruction of the evolution of the Oman-UAE Thrust Belt. We conducted an integration of detailed multiscale remote sensing study, a review of available surface/subsurface data, and our own field geological surveys, and propose a new revised stratigraphic framework which resolves some of the previously raised perplexities, and a new view on the structural evolution of the thrust belt. According to our reconstruction Jebel Hafit is a steep and narrow, elongated, sigmoidally shaped asymmetrical anticline, which stratigraphy shows an Eocene-Oligocene series starting from thick bedded shallow marine carbonate platform (Rus Fm), developing into an instable slope (megaslumps and bioclastic turbidite series),deepening into a carbonate shelf (distal turbidites and cherty limestones) (Dammam Fm). Part of this series was in a later stage diagenetically dolomitised. The complex structural setting results in difficulties in the reconstruction, being topographically and structurally inverted along faults which obliquely cross the anticline. Combining all available data we propose a new solution according to which the structure of Jebel Hafit and similar anticlines is directly linked to deep seated transpressional faulting, instead of related to folding and back-thrusting along low angle thrusting which characterises, instead, the older portion of the Oman-Emirates thrust belt. In our new regional model, the thrust belt displays an evolution from thin-skinned to thick skinned tectonics, starting from Cretaceous up to Present day. In Late Cretaceous times, the area was characterised by the thin-skinned over thrusting of ophiolites and basinal carbonate series towards the southwest and was with the Makran Range part of one accretionary thrust wedge, which extended from Pakistan up to the southern area of Oman. This external part of the thrust belt was sealed by the Maastrichtian-Paleocene-Eocene deposits and became part of the Miocene foreland Basin (extension of the Zagros Basin). This Basin became deformed, during Plio-Pleistocene times, along a major NNE-SSW trending dextral thick-skinned thrust belt comprising the present day Musandam-Emirates-Oman mountain belt, along the SE- border of the north-eastern moving Arabian Plate. The low angle contacts and unconformities of Late Cretaceous up the Miocene times have been deformed by these pulsating progressive movements which were responsible for the transpressional structures like Jebel Hafit, at the frontal zone of this thrust belt. Our analyses show that the complexities observed in the surface and the subsurface can be fit into one comprehensive model which incorporates, though, different tectonic styles, and unites the information available for the various geographical areas into one uniform model.

Abstract Our present-day understanding of the Barremian-Aptian depositional systems of the United Arab Emirates (UAE) is predominantly based on the data from the Eastern part of UAE, as well as on the data from the neighboring Oman. With the increasing interest in the development of the petroleum resources in the Western portion of Abu Dhabi, we need to utilize the existing data, which are available. Approximately 1400 feet of the archive core belonging to the Thamama Group and distributed in 5 wells were analyzed sedimentologically and petrologically. The emphasis was put on the comparability with the existing models from the Eastern portion of Abu Dhabi and to the spatial distribution of distinguished lithofacies. Analyzed sediments are divided into 20 sub-lithofacies, grouped within 8 main lithofacies. Thicknesses, stratigraphical, and spatial distributions of each sub-lithofacies are given. Color and fossil assemblage complement descriptions. Finally, a short commentary with possible interpretations of a depositional environment fulfills each sublithofacies’ characterization.

Abstract A Reservoir Rock Typing (RRT) and Saturation modelling integrated study of the Lower Cretaceous Group reservoirs in Field X was conducted as part of required inputs into an ongoing FDP update. The results of this study allowed for a robust 3D modelling workflow that included saturation height modelling of the observed tilted oil water contact in the acquifer underlying three (3) of the major hydrocarbon bearing zones. The study intervals covered intervals that for the purpose of this paper will be called XH-4, XH-1, KX-2, XK-3 and XK-2 zones. Rock types were defined using core data integrated with geological descriptions and 3D distributed taking into consideration the depositional environments. Porosity, permeability and saturation property distribution was guided by the RT distribution. In total 44 wells in the field plus 4 nearby wells were incorporated in this study. This paper analyses the petrophysical, geological and static modelling workflows utilized. The RRT definition was based on the prediction of Self Organising Map (SOM) electrofacies which were classified using the petrophysical grouping obtained from lithofacies and depositional environment, permeability and MICP data. As a further step, the predicted RRT was optimised where the Archie saturation indicated that a different rock type was more likely. The analysis of virgin formation pressure data to understand the tilted OWC/FWL concept reveals that different wells have different absolute pressures. When the differences are mapped no regional trends were observed which makes a hydrodynamic origin of the tilted OWC/FWL less likely. Free water level (FWL) has been interpreted on well by well basis and mapped across the field for a better understanding of the variation. The pressure data are consistent with the scenario that the XH-4, XH-1 and KX-2 zones all share the same free water level for modelling purposes. The OWC is more or less flat in the central field area and is about 35 ft deeper in the eastern part of the structure. Although the difference in OWC could be abrupt (compartmentalisation), a gradual tilt seems to fit the data better. Furthermore, the ‘deepest oil observations’, which relate to paleo conditions, are deeper than present-day FWL in the east. All these observations would be consistent with a structural tilt towards the east. Similar trends were also observed from the FWL interpreted across key wells having formation pressure data. In terms of reservoir quality, the interval XK-3 has highest porosity and highest permeability. Also XH-1 and KX-2 contain good reservoir quality rocks. XH-4 is located above XH-1 and KX-2 and has relatively low quality matrix properties. It does contain low porosity (and hence brittle rocks) that can be expected to contain oil when fractured. The deeper XK-3 is probably disconnected from the underlying XK-2 which can be explained by the argillaceous interval between XK-3 and −2. XK-2 consists of thin reservoir intervals so that both Archie saturation estimates and the rock typing work carry significant uncertainty. The derived saturation height (SH) models utilise both a present-day and a paleo free water level per well. Each reservoir interval has its own SH-model based on SH-functions for each RRT. Implementation of all defined RRTs with associated SHFs was done to allow for highest resolution population of the geomodel, though a significant number of algorithms is required for this process. The RRT population of the static models was designed to be obtained from the combination of 3 distributed parameters: porosity, depositional environment, and reservoir quality by using the algorithms provided. Reservoir Quality is the driver most closely linked to diagenesis and local permeability variations.

Abstract The Nong Yao field is a marginal oil field that presents many challenges, both geological (thin hydrocarbon column and structural uncertainty due to shallow gas effects) and with well design (shallow depth and unconsolidated reservoirs). The field has been on production for almost five years with water cut in most wells now over 90%. The key to extending field life is identifying new infill locations, with advanced technology required to identify and drill these targets. To improve seismic image and structural definition, the seismic data was reprocessed in 2016, utilizing the latest technologies including Broadband Processing and Full Waveform Inversion. This detected local unswept structures and thin reservoirs allowing for identification of infill targets. New generation hydrocarbon saturation cased hole logs were run in wells to identify swept versus bypassed oil areas. Many infill opportunities required complex 3-D well trajectories and innovative completions. To achieve these objectives, technology such as high build rate rotary steerable systems, advanced real time survey corrections, a multilayer bed boundary detection tool, rotational friction transducer and inflow control devices were implemented. After four years of production, a key well exhibited significantly more production than expected, indicating a much larger reservoir than modelled. However, water cut in this well had reached 98%, so infill wells were required in order to extend production. The reprocessed seismic indicated that the structure extended further to the east of the existing producer than initially modelled. A cased hole saturation log was acquired in an existing well drilled near the planned landing location, which showed that the reservoir was actually swept in this area. Instead, the infill well was landed and drilled in the opposite direction in this eastern part of the structure, keeping the heel away from the water, but providing a much more challenging well path. A high-build rate rotary steerable system, advanced real time survey correction and rotational friction transducer were used to safely deliver this complex 3-D well profile and avoid collision risk from offset wells. The multilayer bed boundary detection tool was then used to ensure the horizontal well stayed as high as possible whilst remaining within the reservoir. Lastly, an inflow control device was installed in the horizontal section to delay water production. The well came online with 0% water cut and is an excellent producer. Similar methods have been adopted at other locations to identify and drill infill targets with great success. Collaboration across disciplines is key, as input is required from the geologist, geophysicist, petrophysicist, reservoir engineer, drilling engineer and completion engineer to identify, drill and produce these infill targets. Implementation of this approach continues to add new volumes and extend field life.

Abstract Typical carbonate reservoir modelling workflow usually requires the definition of a carbonate facies model. It generally consists of a conceptual model that drives the successive stages of populating reservoir models. Intuitively, the process of defining a facies model helps to understand and master carbonate reservoir heterogeneity at all scales. This convenient approach reduces the obvious complexity of carbonate reservoirs. It also supports many scientific and technical activities from stratigraphic well correlation, sedimentology, petrophysical interpretation, identification of key dynamic features and assessment of uncertainties to be captured in numerical reservoir models. In practice, facies models bridge the gap between natural processes (sedimentology, diagenesis) and rock properties at reservoir scale and deliver the elementary bricks for the numerical reservoir models. However, such conceptual models mostly derive from scattered observation data (few wells with cored intervals) rarely supported by physical measurement. This limitation induces significant uncertainties in the definition of sediment profiles, depending on the scale and the concepts used. All models produced are the result of extrapolations and interpretations, from cores data which do not sample the whole space of sedimentation. The interdisciplinary ALBION R&D project aims at studying Urgonian carbonate formation from south-east France, known as a famous analogue of Kharaib & Shuaiba Middle East reservoirs (both of Barremian-Aptian age). The quality of the numerous outcrops, the completeness of the available material (e.g. cores, rock samples, thin sections, various and advanced analyses) and the importance of the published bibliography allowed to define a complete and synthetic facies model to be compared with the ones of Kharaib and Shuaiba formations from the United Arab Emirates. The workflow implemented to realize the facies model on the Urgonian and the Kharaib - Shuaiba formations takes place in four stages: 1) Comprehensive synthesis of the literature; 2) Consistency and ranking of the available data; 3) Creation of the table and facies models; 4) Definition of parameters controlling the occurrence of facies association (e.g. bathymetry, energy). This innovative workflow enforces the coherency between the definition of each facies and the facies association populated in the numerical reservoir model. It makes also possible/easier the comparison between different facies models. These new facies models are embedded within a carbonate infrastructure ranging from the carbonate system (carbonate factory) to the facies of deposits. Facies are characterized by physical quantities such as bathymetry and energy (controlling processes). The construction of these two facies models (representing both sides of the Neo Tethys) drives the definition of numerical modeling rules shared by the two sectors. It opens important perspectives to testing process based and geostatistical numerical modeling methods on the Urgonian outcrop to better control stratigraphic architecture, facies organization in carbonate production prior to applying ascertained modeling rules to Middle East subsurface reservoirs.

Abstract The Jurassic stratigraphy of the Middle East includes the world's most economically significant petroleum systems, containing multiple world-class source, reservoir and seal packages. Yet in a regional context, these depositional systems are still not fully understood, leading to inconsistencies in lithostratigraphic nomenclature across international boundaries and misconceptions in the stratigraphic architecture limiting exploration and production success. We have applied sequence stratigraphic principles across the Jurassic strata of the eastern Arabian Plate to increase stratigraphic understanding and resolve some of the common misconceptions. This provides a robust age-based framework to reduce lithostratigraphic uncertainty across international boundaries and provides predictive capabilities into the temporal and spatial distribution of source, reservoir, and seal facies. Herein, we focus on one of these stratigraphic misconceptions, which deals with the development and sedimentary infill of the Late Jurassic Gotnia Basin, and its relationship with the aggrading platform of the Rimthan Arch. Our literature based re-interpretation proposes a mostly eustatically driven control, whereby the shallow water platform of the Rimthan Arch followed sea level rise, and the Gotnia Basin became a starved intra shelf basin. This revised stratigraphic interpretation has important consequences for the lateral facies relationships, and overall tectono-sedimentary understanding of the area, as well as for the petroleum habitat.

Abstract Single-well chemical tracer tests (SWCTT) have received burgeoning interest as in-situ methods to measure the remaining oil saturation (S_or). The test not only involves field operations and lab measurements, but also relies on curve fitting of the data acquired from these procedures. Despite various types of errors and uncertainties arising in SWCTT, their effects on data analysis, and in turn the accuracy of S_or measurements, remain unclear. Here, we present a robust SWCTT simulator and use it to perform sensitivity analysis of different parameters over a wide range of reservoir and tracer properties. We find that accurate determination of tracers’ partition coefficients is crucial for estimating S_or, whereas errors in concentration measurements or pore volume characterization have less dramatic effects. More importantly, we demonstrate that matching the SWCTT data is only a necessary condition for the accurate estimation of S_or. In fact, a good data fitting without correct values of parameters such as partition coefficient could yield substantially deviated values of S_or. This sensitivity analysis and the "what-if" capability of our simulator provide in-depth understanding for the design and optimization of SWCTT.

Abstract This paper presents the integration of two surveillance technologies, inflow & inter-well tracers in an Abu Dhabi Offshore field, for the first time to monitor a complex multi-layered reservoir with early stage water injection. Inflow tracers are chemicals with unique identities, installed into the lower completions that penetrate different layers in the reservoir. Inter-well tracers are also unique chemicals injected into injection wells. Tracer technologies allow non-electric wireless monitoring of the reservoir for many years while reducing cost and operational efficiency. In both technologies, data capture requires to fluid samples to be collected and analysed to detect the unique tracers in the production wells. Inflow tracers provides both qualitative and quantitative estimates of zonal flow as well identifying the source of water breakthrough. Inter-well tracers introduced in the injection wells can identify the primary flow paths and rate of movement of injected fluid in the reservoir. This information can be used to evaluate water channelling and improve water flood conformance plans to maximize sweep efficiency. The planning and design stage included a selection of pumpable inter-well tracers, volume calculation and breakthrough time simulations to determine the tracer mass required to meet the monitoring objectives. On the other hand, inflow tracers were designed to account for high temperature and highly acidic stimulation fluids and placed along the producing intervals in the lower completion. Quantification models will be utilized to quantify the zonal influx while accounting for expected cross flow. The execution plan is defined by the optimum production and injection rates, equipment and lab test requirements, and optimized field sampling schedule for transient and steady state flow campaigns. The co-implementation of both tracer technologies in the early stage of waterflood development offers unique ability to monitor the reservoir, eliminating the need for expensive, complicated offshore logistical arrangements for time-consuming wireline interventions to manage the reservoir more efficiently and maximize recovery.

Abstract Reservoir characterization is a key element of asset evaluation and optimal field development strategies. Accurate water saturation evaluation and permeability profiling are crucial parameters in determining volumetrics and productivity of the multiple, stacked carbonate reservoirs in offshore Abu Dhabi and derisking the reservoir management process. The main objective of this paper is to look at saturation and permeability interpretations by comparing the various static and dynamic logging measurements. Archie in 1942 postulated the water saturation calculation equation for sandstones, but it has also been used in carbonates because of its simplicity. Multiple authors have understood the effect of different textural parameters on water saturation calculation and have come up with different workaround techniques. The current case study illustrates how the integration of static measurements, such as dielectric dispersion and nuclear magnetic resonance (NMR) with dynamic measurements improves our understanding of the reservoir properties (saturation and permeability), and in turn support a more accurate reservoir evaluation. Sampling and downhole fluid analysis (DFA) performed by the wireline formation tester (WFT) identifies the fluid and rock properties in the various flow units. One key observation in this case study is how the conventional Archie-based equation has struggled to provide satisfactory and accurate water saturation results in this reservoir, whereas the dielectric dispersion measurement proves its value by providing direct water volume measurement that is validated with the fluid pressure gradient and the sampling results. The WFT sampling and DFA stations—which account for the flowing fractions and the hydrocarbon characterization—are followed by an extended build up, otherwise known as mini drill stem test (mini-DST). The radial flow regime is used to derive the horizontal/radial permeability across the tested interval. Mini-DST measurements provide a depth of investigation much deeper into the reservoir compared to standard core or log analysis, yet at a fraction of the operational times typically needed by a full drill-stem test. This integration of static (saturations and permeability) with dynamic measurements (DFA and Mini-DST) aids in providing accurate reservoir characterization and better understanding of its properties. Multifrequency dielectric measurements add a weapon in the arsenal of the petrophysicist and can be used in conjunction with dynamic measurements from the wireline formation tester to understand the rock and fluid properties and get a better understanding of the Cretaceous reservoirs of interest in offshore Abu Dhabi.

Abstract Hydraulic fracture design driven by multi-disciplinary collaboration can maximize the production potential of complex multi-frac horizontal wells. Integration of multiple information sources (i.e.: geological, dynamic and geomechanical data) allows to build representative models and have proven to improve modelling towards a realistic understanding of tight reservoir performance of several multi-fracced wells. 3D properties encompassing the reservoir geological heterogeneity, pore pressure, mechanical elasticity and state of stress were utilized to develop a strategy to fracture stimulate a horizontal wellbore in the North Sea Region. The study was instrumental to build fit-for-purpose hydraulic fracture designs by incorporating state of stress changes related to pore pressure depletion on different faulted compartments supported by a reservoir dynamic simulation. Such models provided meaningful value to optimize the well trajectory used to access the host rock, understand fracture height growth possibilities in different compartments and define the number/size of hydraulic fractures required for optimum production.

Abstract Our new Petrophysical Rock Type (PRT) prediction method is based on Advanced Multi-Well Flow Units. The new PRT method uses a variation of the Multi-Component Stratigraphic Modified Lorenz Plot. The advantage is, the new method directly links PRT and flow units together at the field and well levels. The advanced flow unit analysis is used for asset management, identifying and comparing completion zones, finding remedial opportunities, comparing petrophysical rock types from several approaches and aid geoscientist in identifying potential new well locations before building a 3-dimensional static model. The new Multi-Well method includes core analysis, well performance data and well logs over the zone of interest. This method has been applied in conventional carbonates, sandstones, low permeability "tight" reservoirs and unconventional shales (gas or oil). A key reservoir characterization feature is the ability to determine petrophysical rock types directly using non-normalized total storage capacity, total flow capacity and bulk volumes of oil and water without using pore throat techniques. Our PRT and Advanced Flow Unit workflow process includes the following steps; Determine total storage volume by integrating core and log data. Computed bulk volume water and hydrocarbon are determined by integrating core and log data. Flow capacity is determined by integrating conventional core analysis, special core analysis and well log data over the zone of interest and pressure analysis. Field or multi-well Composite Diagnostic Non-Normalized Modified Lorenz and Classic Lorenz plots are used to predict Petrophysical Rock Types per well using non-normalized data (total storage capacity vs. total flow capacity) as a function of depth. Determining field or multi-well Composite Diagnostic Non-Normalized Multi-Component Depth Domain Analysis plots include cumulative total storage capacity, cumulative total flow capacity, cumulative bulk volume water capacity and cumulative bulk volume hydrocarbon capacity. These plots are used to evaluate and compare well performance. Per well or composite Multi-Component Diagnostic Stratigraphic Modified Lorenz Plots are created as a function of depth and can be integrated with well test data or well performance data to provide another well evaluation tool for reservoir management. Slope analysis, slope difference and data smoothing are completed at the well level to automatically predict PRT. The results are compared to deterministic methods to access the quality of the PRT prediction. Slope analysis, slope difference and data smoothing are completed on a "super well or composite well" Classic Lorenz plot using results from high quality core-log integration analysis from multiple wells. The super well composite plot is used to predict the number of PRTs in a field for a zone. Resulting PRTs should be verified using the 10-Step process that we described in 2018 (SPE). The benefits of this new method include, the field analysis and well-to-well comparisons of reservoir compartments and the petrophysical rock types identification using derivative analysis. Applying this multi-well method in mature fields provides a quick method of evaluating existing wells to identify bypassed hydrocarbon and zones that have a high probability of producing water. Potential infill drilling locations or zone recompletions can be evaluated before creating a detailed static or dynamic reservoir model. In the future these methods may be combined with "Artificial Intelligence or Machine Learning" using well monitoring data to identify anomalous performance.

Abstract Well integrity management is a prime global focus area for all oil and gas operators. Any field-wide corrosion challenge requires a substantial investment to manage the integrity of assets and, consequently, to maximize life expectancy and efficiency. Over decades, the industry has concentrated its efforts toward containing fluids from any unintentional release at the surface occurring as a result of corrosion. This paper highlights the most recent electromagnetic (EM) logging technology developments to address well integrity challenges. Three primary corrosion mechanisms occur in oil and gas wells: chemical, mechanical, and electrochemical. Electrochemical corrosion is the mechanism responsible for most of the failures in which the outermost casing is exposed to corrosive fluids and is consequently penetrated first. As the corrosion process continues, subsequent well barriers are progressively corroded until the inner casing or tubing is in direct contact with a corrosive environment and at direct risk of a major well integrity failure. As a result of this outside-to-inside corrosion mechanism, the early diagnosis of the outermost casing status is especially important as a proactive measure to identify any potential weak zones in the completion string. This early diagnosis is a major step to optimize well integrity intervention and to optimize workover operations costs. Cathodic protection and coated casing are used to extend the life of the well by controlling corrosion; however, these are only mitigation measures that slow down but do not eliminate corrosion. EM logging technology provides an effective method for monitoring and identifying the effectiveness of these corrosion mitigation measures. Time domain EM pulse eddy current (PEC) technology has facilitated corrosion evaluation by logging through tubing, thereby avoiding the cost of pulling completions solely for surveillance purposes. The latest EM PEC technology, the enhanced pipe detection tool (ePDT), provides individual barrier thickness measurements for four concentric pipe strings. The innovative features of ePDT include: (1) A fractal transmitter (Tx) coiled array that improves the performance of the tool with enhanced signal-to-noise ratio (SNR) covering a wide signal dynamic range, and adaptability for various logging speeds and spatial resolutions for varying pipes; (2) a synthetic aperture of the receiver (Rx) coil array for noise compensation from extraneous tool motion; and (3) a wide-spatial aperture Rx coil array which, when combined with (1) and (2), enables the compression of the inner pipe remnant magnetization interferences without sacrificing spatial resolution. This paper demonstrates ePDT benefits by benchmarking to other technologies and control environments. The results are discussed in detail to provide an overview of EM technology, as well as the advantages and limitations. Ultimately, the answer product from this technology is integrated with other current and historical information related to the well or field being evaluated as part of the well integrity management system (WIMS). Finally, it is important to expand the technology operating envelope beyond the standard applications to address larger completions challenges, such as gas wells and landing base inspection, by extending the tool capabilities while optimizing data acquisition and processing methodologies.

Mass-transport deposits are sedimentary, stratigraphic successions that were remobilized after initial deposition but prior to substantial lithification and transported downslope by gravitational processes as non-Newtonian rheological units (Bingham plastics or dilatant fluids). The deposits are not associated with a specific stratigraphic position. Mass transport complex (MTC) reservoirs currently under study in Colombia, consist of complex mixtures of metamorphic and igneous rocks with matrix porosities in the 3%-6% range, complex mineralogy, strong localized mylonitization effect and naturally fractured. The reservoirs are in the Lower Magdalena Valley hydrocarbon province in northern Colombia. In this context, the objective is to achieve an accurate porosity determination, water, gas, oil saturation computation and natural fracture assessment in an exploration phase, with scarce background on electrical logs response and petrophysical models in these types of environments. In wildcat conditions, the lack of formation properties knowledge is detrimental to achieve a representative formation evaluation and reservoir potential understanding. While this is true even in relatively known geological environments (siliciclastics, carbonates, for instance), in Mass Transports deposits the complexity is even higher, given the mineral mixtures, heterogeneities, poor rock quality, complex tortuosity and complex natural fractures networks, among other challenges. In this paper, we present an open hole advanced formation evaluation approach that enable to assess the tight matrix and the natural fractures systems, at a level not previously accomplished in these types of geological formations. At the matrix, advanced nuclear spectroscopy that does simultaneous time and energy domain measurements was integrated with a high-resolution magnetic resonance with improved sensitivity at short relaxation times. This allowed an archie-independent methodology for assessing gas from a new Fast Neutron Cross Section measurement, followed by liquid hydrocarbon fraction from the total organic carbon log and matrix-corrected porosity from combining hydrogen index and dry weight elemental concentrations. For natural fractures, the integration of borehole images with radial sonic-based dispersion and stoneley analysis, was carried out. The main advantages of the new method for obtaining porosity, mineralogy, archie-independent hydrocarbon saturation in tight matrix and natural fracture assessment are: 1) conversion of fast neutron cross section to gas saturation and dry weight total carbon to oil saturation, done through a simultaneous inversion by solving matrix-porosity-fluids volumes into an elemental analysis, proven to work at low porosities; 2) reservoir quality assessment from a high sensitive and high resolution NMR T2 relaxation; 3) independency of archie equation parameters, typically unknow in wildcat environments; 4) reservoir potential uncertainty reduction; 5) identification of the natural fracture systems that can contribute to fluids production.

The paper discusses the conceptualization, design and implementation of an interwell waterflood passive chemical tracer study in stacked naturally fractured carbonate reservoirs, in a Field in the Sultanate of Oman. The reservoir structure is an almost undisturbed directionally trending anticline, intercalated by several fault zones at the southern flank, running parallel to the structural axis. The shaly intercalations intercepting the chalky reservoir add another layer of complexity to the fractured reservoir system. During the 1960s, the field was first put on fracture spurt production which then rapidly declined by the 1970s. Thereafter, a peripheral water injection program was introduced followed by a gas oil gravity drainage to stabilize production rates. To manage the uncertainties arising out of the complex geology and develop the field in the best techno-economic fashion, it was imperative to gain understanding of the fluid flow dynamics operating within the reservoir that was dominated by the complex fracture-matrix system. Over decades, chemical tracers have been a proven and reliable source to gather such information. Over the past years, several studies using interwell passive water tracers were conducted in the field, covering various areas of interest. The design of the tracer study in a fractured system is more complex than designing the same for simple hydrodynamic applications. Complexities including preferential fluid influx through layered reservoirs, competing fracture matrix movement and relatively faster breakthroughs amongst other things required to be considered. Connectivity between overlaying reservoirs was suspected to affect flow dynamics but not confirmed in water flooded areas. In this case, another layer of complexity was added due to re-injection of produced water that required meticulous understanding of the pseudo breakthroughs. The paper discusses the challenges in design, implementation, interpretation and simulation when carrying out a passive chemical tracer study in a fractured reservoir and the best practices adopted to counter them. The case study also discusses immediate oil gain, the qualitative and quantitative results obtained from two large scale tracer studies involving fourteen injectors and 36 producers and six injectors and nineteen producers carried out in recent years and explains the results in light of mean residence time, swept volume, sweep efficiency and heterogeneity indices. Additionally, the study also discusses numerical tracer simulation modelling. To date, available literature only explores the concept of complex tracer studies in fractured reservoirs through numerical simulation models. To the best of the authors' available information, this study is pioneering in the provision of best practice guidelines when designing such a study with respect to volume assessment, operational challenges, design of customized sampling and analysis plans, qualitative and quantitative interpretation of the data obtained as well as modelling aspects.

Development of low-permeable oil reservoirs with complex bedding often requires application of production stimulation methods such as hydraulic fracturing. Success of well stimulation greatly depends on quality of geomechanical and hydraulic fracture models. Several different workflows can be used to build a certain model when the input data available are necessary and sufficient. However, in the absence of some of the key data, it is necessary to use rational assumptions instead, but doing so automatically regards model output as probabilistic. This paper concentrates on steps necessary to constrain initial assumptions made within models and demonstrates the result obtained. We present an integrated workflow used for cross-validation of geomechanical and hydraulic fracturing models based on production history match as a constrain. Relatively thin 35 deg API oil-bearing ∼ 0.3 mD hydrostatically pressurized zone, represented by interbedding of heterogeneous sedimentary layers of gross height of ∼ 15 m out of which about 5.5 m is pay, with argillitic barriers at top and bottom (see Fig. 2 ) has active water-bearing formation 45-50 meters above. Production history available for stimulated horizontal wells has shown a significantly increased water-cut compare to one expected from the zone of interest. Earlier frac company stress models were made by tying pressure gradients - "regional experience" - to gamma ray and SP logs and attributing E, KIc to lithology. These fracture models were consistently showing hydraulic fracture containment by barriers of the target zone and, thus, fracturing into water zone was not viewed as a highly probable cause of an increased water cut. Our target was to resolve the water cut problem by means of geomechanical and retrospective hydraulic fracturing modeling. These two models were initially built on incomplete data due to the absence of: pore pressure measurements mechanical properties (static Young's modulus) from core analysis. The models were then cross validated by constraining on production history while utilizing Young's modulus as variable. PEBI-grid based reservoir simulator is fully coupled with finite difference planar full-3D hydraulic fracturing simulator and allows direct transfer of fracture geometry (conductivity) for multiphase flow simulation.