Abstract Cenomanian carbonate deposits of Shilaif Formation, located west of Abu Dhabi, exhibit a high degree of heterogeneity at multi scales. To characterize this formation and explore its hydrocarbon potential, several geological, petrophysical, and geochemical analyses, including digital rock analysis (DRA), were applied and integrated. A hundred ft of whole core were logged at the surface using dual-energy X-ray CT (DECT) and Spectral Gamma (SGR) to generate bulk density, photoelectric factor, and gamma logs. Based on integration between DECT, SGR, and wireline logs, high-resolution total organic carbon (TOC), brittleness index, and mineralogy logs were generated at a millimeter scale, and representative core samples were extracted. Inorganic and organic geochemical analyses represented by X-ray diffraction, LECO TOC, HAWK pyrolysis, vitrinite reflectance, and hydrocarbons chromatography (SARA) were performed on selected samples to define rock mineralogy, type, and degree of organic matter maturity and chemical composition of the hydrocarbons. Nuclear magnetic resonance (NMR) at native, dry and full-brine saturation conditions, mercury injection capillary pressure (MICP), and crushed rock analysis (CRA) were conducted on selected samples to determine fluid saturations, porosity, permeability, and pore-throat-size distribution. The pore-scale analysis was also performed using argon-ion-milled SEM images to quantify organic matter contents and total, effective, and organic matter porosities. All core data obtained at multiscale were integrated with the wireline and generated high-resolution logs to validate and select optimal horizontal leg landing zones. DECT and SGR logs showed the top of Shilaif is mainly made of calcite, while its bottom is calcitic with minor concentrations of clay minerals and pyrite. Integration between DECT and SGR logs showed the mid and bottom of the formation have high radioactivity attributed to the presence of organic matter in intermediate concentrations and the presence of clay minerals. Pyrolysis analysis indicated a kerogen type I to II with an average Tmax equal to 431°C. Measured and calculated vitrinite reflectance (Ro) was, on average, 0.59, confirming that the kerogen of Shilaif in the area of study falls within the immature to the early mature oil window. Measurements such as CRA, MICP, NMR, and 2D SEM analyses showed that Shilaif has low porosity of approximately 3% on average and very low permeability averaging 0.00057 mD. The 2D SEM images and NMR data confirmed this and revealed that it lacks the porosity associated with the organic matter resulting from its low degree of transformation. Lab data and upscaled petrophysical logs showed that Shiliaf in this field has a low degree of thermal maturity and fall within the early oil window. Integration between core analysis results and wireline data helped understand the Shilaif Formation characteristics and determine its hydrocarbon potential. It also provided additional calibration to the wireline data.

Abstract Oil leakage, due to well integrity issues of varying proportions, from downhole completions is a common phenomenon despite all measures and adherence to regulations. These leakages potentially could cause environmental damage through surface spill, aquifer contamination and in worst-case scenario loss of human lives. In an offshore setting, impact of well integrity issue can be more severe than in an onshore well due to complex and often costly offshore well operations. Downhole completions including cement quality deterioration occurs with the passage of time due primarily to corrosive nature of hydrocarbons produced from a well. Oil companies perform routine well integrity surveillance by acquiring real time annulus pressure data, cement bond, temperature and sonic logs to assess well integrity and perform remedial measures, if and when, required. Leakage may also occur in a complex pattern from nearby wells and different reservoir than the suspected reservoir and show up in the annulus or eventually on the surface. Whilst, well integrity surveillance data indicates leakage when it occurs, finding the exact source location of leakage is often difficult. Objective of this study was to perform a cost-optimized reservoir to annulus leakage oil correlation using geochemical methods in an offshore well to establish the source of oil in the annulus.

Abstract Wrench fault system is the predominant regime of Abu Dhabi tectonics and their related damage zones influences the stresses between the fault segments and hence representing the main controlling factors in field development of hydrocarbon. The strike-slip structures are related to the activation of sinistral strike-slip shear zones oriented N75°W, which initially inherited in the Arabian Plate craton and activated trough the geologic time. The main reactivation happened with the Late Jurassic- Middle Cretaceous and then by the Paleocene and finally by Late Miocene. These reactivations accompanied with block rotation of the stress tensors from NE-SW to NW-SE and finally by NE-SW respectively. The identification of transpressive and transtensional structures are the main concept of locating the hydrocarbon provinces. During the transpressive stage, sinistral transcurrent movements along the Abu Dhabi Shear Zones led to the activation of a multiple set of parallel sinistral faults, conjugate and antithetic to the master fault. The activation of these structures determined a deformation by block rotation that provoked an overall anticlockwise rotation of (N150° to N120°) of 30°. The data show how the rotations occurred might be caused by the activation of multiple strike-slip fault sets and that the rotational mechanism around vertical axes is connected to transpressive tectonics. The use of kinematic and geomechanical models allow quantification of the blocks rotation due to the combined action of multiple sets of strike-slip faults with modest displacements and to demonstrate that the rotation of blocks and their lateral movement constitute two different, contemporaneous expressions of a single deformational event. A systematic classification of the rotational zones and their influences on reservoir behavior was addressed. Classification of stressed zones favoring reactivation based on their location relative to fault segments growth. Therefore, development of structures were combined with fluid flow in/between fault segments to characterize placing wells for an effective field development plan.

Abstract One of the reservoirs in a giant field in onshore Abu Dhabi has been producing for six decades. The reservoir was already saturated at the time of production commencement, with a large oil rim and a gas cap. Both water injection and lean gas injection have been relied upon to sustain production, and will play an even more prominent role for the future development of oil rim and gas cap. Due to the stakeholders’ different entitlements / equity interests in the hydrocarbons originally existed in oil rim area versus gas cap area, it is important to be able to allocate liquid hydrocarbon production and injection gas utilization among the stakeholders, based on a systematic framework. This paper presents a comprehensive comparison of two modeling-based approaches of fluid tracking for condensate allocation and gas utilization – a tracer modeling option in a commercial reservoir simulator, and a full component fluid tracking approach implemented for this reservoir. The component tracking approach is based on the idea that if individual components represented in a fully compositional reservoir model are tracked separately starting from model initialization, one can trace back the source of hydrocarbon production from both gas cap and oil rim. This approach is implemented through the doubling of the number of components in the equation of state fluid characterization – one set of components for the gas cap, and another set for the oil rim. In order to track the net utilization of the injected lean gas, additional components are needed – in this case one more component representing the lean gas, as the injected gas is a dry gas. The results of the comprehensive comparison demonstrate very clearly that these two approaches yield consistent condensate allocation and gas utilization results over the entire life of field (including history match and prediction). For condensate allocation, the hydrocarbon liquid production split depends on how the injected lean gas is tracked. For gas utilization, the injected lean gas must be tracked as a distinct component separate from both oil rim and gas cap components. The comparison also shows that although the tracer-based approach is numerically more efficient with less runtime, the full component tracking approach is simulator agnostic, and therefore can be implemented in any reservoir simulator. In addition, the full component tracking method can be used for cases where injection gas is a known mixture of oil rim and gas cap gas – something the tracer-based option cannot handle. In summary, this paper presents a first comprehensive comparison of the two (2) different fluid tracking modeling approaches, with practical recommendations on modeling-based hydrocarbon liquid production and injection gas utilization allocation in cases where the commercial framework makes such allocation necessary.

Abstract Unconventional Resources (UR) are developing an upstream gathering network, a Gas Separation Plant (GSP), and transmission pipelines for a shale gas development project, based in the eastern region of the Kingdom of Saudi Arabia. The aim of these facilities is to produce nonassociated gas from several unconventional fields with minimum treatment, prior to transmitting both gas and condensate to existing facilities for further treatment. Uncertainties in subsurface and reservoir data for shale gas fields is one of the most challenging aspects of designing surface processing facilities, due to the varied behavior and properties of the production fluids, including rapid depletion in well pressure, Water Gas Ratio (WGR), and Condensate Gas Ratio (CGR). The intent is to design efficient, cost-effective facilities, which can accommodate the expected operating envelope throughout early-life, mid-life and end-life of the facilities. This abstract will focus primarily on three optimization areas already implemented in the facilities design: (i) Gas gathering system. (ii) Dehydration and propane refrigeration. (iii) Off-gas system. The gas gathering system has been designed to be operated in three separate phases: (i) Early Life; (ii) Mid Life; and (iii) Late Life, as the well pressures naturally decline. The selected configuration, compares with other facility designs which incorporates separate High Pressure (HP) and Low Pressure (LP) gathering systems. However, in order to minimize CAPEX, the facility has been designed in a flexible arrangement to be operated over the three different phases. Therefore, the operating pressure will be reduced and the wells choked back accordingly. Tri-ethylene Glycol (TEG) Dehydration unit design has been optimized in the GSP by pre-cooling the process gas upstream of the unit. A small propane refrigeration system was used to chill the upstream process gas. The system reduces the TEG Regeneration equipment sizes, heating duties, and minimizes TEG losses. In addition to that, the propane refrigeration system has been further optimized by utilizing a gas-gas Heat Exchanger (HEX) upstream of the chillers to reduce the required cooling duty. The GSP design includes an off-gas collection system which recompresses Low Pressure (LP) vent streams and recycles them back into the main process gas stream, avoiding the requirement for a LP Flare system. During the Front-End Engineering Design (FEED) stage of the project, the outlet of the off-gas system was routed to the gas transmission pipeline, to comingle with the dry gas from the TEG system. During the project EPC stage, the off-gas system was optimized by re-routing the off-gas to the Medium Pressure (MP) Separator where it is recycled back into the process. This optimization decreases the required off-gas compressor discharge pressure with associated CAPEX and OPEX reduction. Additionally, liquids separated within the off-gas system are also recycled back to the MP Separator instead of a closed drain system, which avoids venting gas that contains concentrated Benzene, Toluene, Ethylbenzene and Xylene (BTEX). This unconventional gas development project will be developed over several phases, and this facility is part of Phase 1 development.

Abstract For the past few years ADNOC has extensively ramped up its effort in exploring and testing unconventional reservoir across Abu Dhabi tight oil and shale gas formation as part of its oil & gas 2030 strategy. Shilaif tight oil exploration started over 5 years ago with multiple vertical wells drilled and tested allowing discovery of stacked tight oil play with significant resources in place. To unlock these resources, horizontal drilling and multistage fracturing were used to confirm recoverable resources, and well potential. Prolific production results have since propelled hydraulic fracturing, hence it has become imperative to build a process to standardize unconventional fracturing technical and operational requirements and to maximize efficiency and benefit. A prime example of such process was in Huwaila-68 where the organic-rich Shilaif shale/tight oil formation was targeted. A target that is analogous to the Eagle Ford from the same Late Cretaceous age. A significant weight is put on reservoir quality assessment to minimize margin of error and increase the probability of fracturing success, and to maximize recovery of the estimated tight oil and shale gas in place. This process assessed the Shilaif from a geological, petrophysical, and geomechanical perspectives. This was followed by setting up preferential staging and perforation placement strategy for fracturing based on reservoir and completion quality which correlated to an initially built 1D mechanical earth model. Production forecasting using reservoir simulations were also utilized to assess fracturing success and deliverability. The processes above led to completing multistage fracturing in Huwaila-68 within the Shilaif formation by means of a pump- down perf and plug operation coupled with high rate slick water pumping, which was followed by extensive well testing. Operational efficiency allowed for the completion of 27 stages placing in excess of 7.3 million lbs of proppant. The use of chemical tracers as a qualitative measure allowed for correlation between natural fracture presence, recorded pumping events, and initially recorded gas shows while drilling. Such observations would help in well placement for future horizontal wells. Post fracturing production rates have met expectations, and were in line with the initial reservoir assessment predictions. The novelty of this paper is the inclusion of several domains to reduce the error margin of fracturing unconventional formations such as the Shilaif. Being an area where field development is rapidly taking place, the inclusion of new technologies have become persistent, and these were evident from the reservoir assessment phase, through to the fracturing phase, and ending with the well testing phase. This level of data gathering and assessment will act as a benchmark for all future unconventional fracturing within the UAE while lessons learnt will further enhance the turnover from drilling to production.

Abstract The objective of this study is to provide an overview of recent waterless stimulation focusing on hydraulic fracturing technologies, advantages and disadvantages, limitations, and new technologies under development. Different technologies are presented including proppant-free such as slurry fracturing and in-situ proppant generation, CO2, LPG, Seawater, plasma fracturing, high power lasers, gas stimulation, exothermic reactants, and high energy gas fracturing. Water-based hydraulic fracturing is commonly used stimulations to recover hydrocarbon specifically from the tight formation. The unconventional reservoir requires pumping and fracturing multistage to maximize stimulated reservoir volume. This technology involves the use of large volumes of high water quality, pumping at high pressure, and filling up the fractures with proppants. Several technologies are presented in an effort to find alternatives to current water-based fracturing technologies. The industry efforts towards waterless fracturing technology are to adapt different technologies into fracturing, for example, the use of plasma to create fractures. The principle of this technology is to store large electric charges and release them in a very short period. Another technology is based on gas combustion to create pressurized gas, which can then create fractures in the reservoir, the use of high-energy laser is used for fracture initiation, and in-situ proppants are targeting chemicals that generate proppant in the fractures. Jetting is also evaluated where acid is injected at a high rate for deeper penetration to create network tunnels. Exothermic fracturing is also discussed which is a technology based on chemical reactions that are triggered at downhole temperatures releasing pressurized gases and creating fractures. Once the drilling operations of a well are concluded, the well is then completed and stimulated. A typical scenario is to perforate the well using a shaped charge perforating gun followed by acid or hydraulic fracturing to maximize reservoir contact. A considerable reduction in permeability can occur when using conventional shaped charge gun, when the fracturing fluid formulation is not appropriately designed, or when improperly flowing back the fracturing fluids. A thorough investigation of recent non-damaging waterless stimulation technologies is included as an alternative to shaped charge gun perforation or to fracturing with water. If conventional fracturing is to be used regardless, then these technologies can be used to help initiate the fracture by lowering the formation breakdown pressure. In addition, it is possible to use these technologies in producing wells to enhance productivity. The discussion will provide details of each technology: suitable use scenario, methodology of use, limitations, and results of case studies. As more and more wells require stimulation to be produced commercially, new non-damaging waterless methods are implemented. The importance of this paper is to show these alternative technologies to increase production and minimize damage to reservoirs.

Abstract Shale rocks are rich in organic minerals, also it contains multi-scale micro-nano pores, making flow mechanism of fracturing fluid in microscopic pores of shale and the interactions between fracturing fluid and shale very complicated. In this study, firstly, the initial microscopic pore structure of shale before hydration was analyzed by field emission electron microscope. Secondly, the dynamic changes of microscopic pore structure in shale hydration was observed at fixed points with the scanning electron microscopy to find out the correlation between induced micro-fractures and mineral components. Finally, the influence of hydration on the changes of shale physical properties was analyzed. The test results of shale sample from Longmaxi formation (LF) in the Sichuan Basin indicate the micro-fractures induced by shale hydration weremainly shale bedding fractures, with obvious directionality. Clay minerals play a leading role in the formation and expansion of induced fractures. After 10 days of hydration, the porosity can be increased by 2.1 times, and the permeability can be increased by 273.7 times. Therefore, an appropriate shut-in treatment can dramatically enhance post-fracturing performance. The research results can guide the optimization of flowback system and provide scientific basis for efficient development of shale gas reservoirs.

Abstract Reservoir 2 shows the same vertical facies stacking pattern across Oilfield A. These facies are observed to be laterally continuous across other oilfields in Abu Dhabi. Multi-scale static and dynamic data show a north to south degradation in reservoir quality across the field. A petrographic, core and borehole image-based evaluation has generated a robust geological concept governing porosity and permeability distribution across Reservoir 2 that is calibrated to seismic impedance and dynamic data. Diagenetic phases were quantified and mapped as part of a detailed sedimentological and petrographic description of Reservoir 2. Samples were analysed for stable isotopes and fluid inclusion microscopy. Chemical compaction features were described in detail in high quality cores. The cored intervals feature abundant preserved samples with up to 30% of the cored interval unavailable for reservoir characterization due to preservation. Consequently, a detailed borehole image description was undertaken and utilized to describe the structural features at log scale and fill in the missing core sample gaps. Petrographic description and mapping shows calcite cement occludes almost all macroporosity in the south of Reservoir 2. The abundance of cement decreases towards the north. Core and BHI based descriptions of chemical compaction features show a higher abundance of stylolites in the south Reservoir 2 than in the north. Most of the primary fluid inclusions trapped within calcite cements are monophase, potential evidence that pore-filling calcite started to precipitate under cooler burial conditions, at temperatures between 60-70°C. It is proposed that stylolitisation is contemporaneous with cementation where carbonate material dissolved during chemical compaction formed the main source for cement precipitation. Reservoir 2 is up to 10% thinner in the south of Oilfield A than in the north. Increased chemical compaction in the south is correlated with decreased reservoir thickness. There is a strong correlation between the pattern of reservoir thickness and P-impedance from seismic inversion. P-impedance is negatively correlated to porosity. Stylolites are most common in reservoir intervals 2A and 2B. These intervals display a wide range of porosity and permeability from north to south, while in contrast reservoir interval 2C, with very few stylolites, has a narrow range of porosity and permeability variation field wide. It is proposed that chemical compaction is the key driver for degrading reservoir quality in Reservoir 2. All scales of static and dynamic data have been reconciled to show that chemical compaction, cementation and reservoir quality are intimately related processes. The implications for producer and injector well design are significant. Depending on the location of the planned well and the development interval to be drilled, well spacing and reservoir contact should vary accordingly, while maintaining the optimal field development pattern.

Abstract In the subject reservoir, geological features (high perm streaks and fractures) are the key performance drivers that affect injected water movement behavior. However the horizontal and vertical distribution of these features have high uncertainties and it is very challenging to accurately capture these features and map into model. Here we developed one workflow to capture these features by integrating different sources of solid data, from core, open-hole resistivity log, PLT, well testing, production and surveillance data, etc. This reservoir has been on production for decades and plenty of static and dynamic data were acquired for the whole field. Among those data, conventional core analysis (CCAL), log derived k-PHIE regression, and well testing will measure reservoir permeability values, which could give guidance to the areal distribution of high perm and low perm regions. Afterwards, the difference between well test interpreted perm and CCAL measured perm could give some indication of some geological features (HKS, fractures, etc.) existing or not. Furthermore, these geological features could be further confirmed by the dynamic data, such as open-hole resistivity logs, PLT, and well production performance data, etc. After confirmation, those preliminary geological features will be mapped into static and simulation models, and the seamless geo-engineering loop of history match process will proceed until the final history match stage without compromising geologic plausibility and consistency. Going through the above integration workflow, the history match process was completed and the final history matched simulation model gives very promising water saturation match quality in both horizontal and vertical directions. In the horizontal direction, ∼90% of the producers get water cut match (trend and magnitude, dWC<5%), and also for recent drilled long horizontal producers (maximum reservoir contact (MRC) wells), model production profiles and water entry points along the laterals have good alignment with PLT and open-hole resistivity log data. In the vertical direction, model water saturation profiles have good alignment with open-hole resistivity log trend for hundreds of wells (∼90% matched). PLT and WFL also have very good match quality. In general this simulation model could reproduce water movement very well in three dimensions using this new integration workflow, with much improvement compared to current the model. It gives higher confidence in the model predictive capacity, and the future field development plan will be studied using this New Generation Model Based on this integrated approach, a more plausible and consistent set of geological features are mapped and thus achieve promising history match quality of water movement with minimum local modifications, and thus enhance the model predictive capacity and provide better support of the life cycle field development.

Abstract The main objective of this paper is understanding the impact of the fractal characteristics of fractured reservoirs on their pressure behavior, flow rate decline, and productivity index. The paper aims to propose a new methodology for developing several analytical models that could be used for describing the wellbore pressure behaviors at a constant sandface flow rate and the flow rate decline trends at a constant wellbore pressure. Considering the fractal characteristics in the proposed analytical models may help eliminating significantly the uncertainties in predicting reservoir performance in highly disordered and heterogeneous formations. The target of this study is the reservoirs characterized by a complex structure and undergoing an anomalous diffusing flow mechanism such as naturally fractured reservoirs with a nonuniform distribution of embedded fractures and depleted by multiple hydraulic fractures. The proposed methodology considers including the fractal characteristics such as the mass fractal dimension, conductivity index of anomalous diffusion flow mechanism, fractal-network parameters, fractional-derivative order, and matrix/fracture-interaction index as well as dual-porosity media characteristics such as the storativity and interporosity flow coefficient in the analytical models of the pressure, rate, and productivity index. These analytical models are derived for the porous media with the fractal networks of fractures that are embedded in the matrix and connected to hydraulic fractures. The porous media in this study are represented by two volumes. The first is the stimulated reservoir volume with a rectangular-shape area of a length equal to the hydraulic fracture length, while the second is the unstimulated reservoir volume that extends away from the tips of hydraulic fractures towards the reservoir boundaries. The solutions of the two approaches of the inner wellbore conditions are demonstrated in this study. The first is the wellbore pressure drop assuming constant sandface flow rate while the second is the decline rate and cumulative production assuming constant wellbore pressure. The outcomes of this study are: 1) Understanding the impact of the fractal characteristics on pressure behavior, flow rate declining pattern, and productivity index scheme during early and late production time. 2) Developing analytical models that consider the fractal characteristics of structurally complex reservoirs depleted by multiple hydraulic fractures. 3) The study has found that some of the fractal characteristics such as mass fractal dimension has a significant impact on reservoir performance while others such as matrix/fracture interaction index may not have a significant impact. 4) Fractal reservoirs exhibit better performance than the standard geometry reservoirs of single porosity media or naturally fractured reservoir with dual-porosity media. The novel point presented in this study is developing a new methodology for including the impact of the fractal characteristics in the pressure, rate, and productivity index models. In these models, the stimulated reservoir volume is assumed as a vertical wellbore with an equivalent radius equal to the fracture half-length. This approach is verified by comparing the results of pressure, rate, and productivity index obtained for a very short fracture half-length with the result of the vertical wellbore wherein an excellent matching is observed.

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 With the rapid development in machine learning (ML) and deep learning (DL) algorithms, computations power and availability of the massive amount of data, ML and DL approaches have gained a lot of interest in oil and gas industry and brought the data science and analytics into the forefront of this industry. Using traditional neural networks (NNs) to normalize log and generate synthetic well logs is not a new idea. However, the recent advancement in ML and DL methods encourages to further research and revisit the prediction power, discuss the methodological limits and further improve the approach and prediction algorithms in single and multi-well synthetic well log generation for reservoir characterization and formation evaluation. In this study a data-driven procedure was implemented based on deep neural networks for density generation using multivariate inputs of well log data. The density prediction was formulated as a depth series regression problem where multiple inputs including different open hole logs are used as the input of a reverse model that estimates density. Different recurrent DL structures including Long Short Term Memory, Gated Recurrent Units, and Bidirectional Recurrent Neural Networks were tested in this study to select the most time-efficient and high performance model for density log generation. The models were fed with different number of available curves to explore a relationship and potential predictive power of several variables on the target curve (density) to eliminate unnecessary and irrelevant curves and end up with a model that uses a few curves to generate the target curve. Training datasets consist of real well log data of 25 wells logged offshore Middle East. Different metrics (RMSE, MAE, and R2) were used to compare the performance of the models and stacked LSTM of three layers showed the highest performance. Using this approach companies could cut costs by generating high quality synthetic data with a faster turnaround and without the need of relogging.

Abstract The paper describes the execution of a successful rigless intervention solution deployed to establish well integrity and restore well production in a field in Europe. The paper will go through the planning and execution of the job highlighting the criticalities encountered and the overall benefit of the activity. The approach used was a deep analysis of the well integrity issue from several prospectives. A new opportunity in the production optimization fluid has been identified. After an open discussion between Customer and contractor, a customized blend and detailed pumping procedure was agreed upon to reach the final scope. An injectivity test was executed to align the procedure to the reservoir and well behavior. Several pressure tests were performed to confirm the remedial job in place, and, after that, the well was re-perforated and opened to the production. The horizontal well described in the paper, shut in during 2016 due to formation damage and depletion was selected for a new through tubing perforations interval by coiled tubing in the horizontal section. An unexpected firing head activation occurred at an unplanned depth, just above production packer. This event produced communication across the production tubing, liner, casing, and formation, which immediately induced total losses into the naturally fractured carbonate reservoir causing well control issues. The accidental perforations could have jeopardized the final scope of the project with no oil production and premature well abandonment. A successful rigless remedial intervention was immediately executed to restore well integrity by using a real time fiber optic coiled tubing acquisition and a new conformance fluid combined with a customized cement packer technique. The remedial intervention allowed the operator to resume the initial project's scope of opening the new perforation intervals, restoring an important oil production of about 150 [m3/d]. The final solution utilized a product with unique thixotropic properties which was then engineered for production optimization using a detailed pumping strategy. This novel approach added significant value, as the operator was able to restore the integrity of the well in rigless mode, avoiding the associated rig cost.

Abstract Cementing of production casing in the Northern Iraq poses challenges to the cement sheath integrity due to mechanical and thermal stresses induced in the well life. The problem is further aggravated due to narrow window between pore pressure and fracture gradient. The acid-prohibitive cement system with improved mechanical properties was developed to mitigate the effect of induced stresses. The job was executed with operational optimization and zonal isolation was achieved. Based on the operator's well testing and multi-stage high-rate well stimulation plan, the stress modeling was carried out to determine the optimum mechanical properties. The 19.6 ppg heavyweight cement system with a flexible thermoplastic polymer was designed to achieve the required Young's modulus and Poisson's ratio. Since the density and friction pressure hierarchy could not be met due to the narrow window between pore pressure and fracture gradient, therefore, the slurry rheological properties were optimized for effective mud removal. The pumping parameters were adjusted to maintain the primary well control during the cementing operation without compromising displacement efficiency. The approach was implemented without any operational issues in the 9-7/8" production casing and 7" liner cementing. Following the job completion and waiting-on-cement time, the 9-7/8" casing was successfully pressure tested with a surface applied pressure of 2,000 psi and a well fluid of 1.78 SG. The isolation scanner cement evaluation confirmed the zonal isolation along the open hole of both the 9-7/8" intermediate casing and the 4½" production liner. Finally, the multi-stage high-pressure stimulation operations were performed during the completion/testing stage with no sign of communication between the different zones. The application of heavyweight acid prohibitive flexible slurry helped the operator to isolate the different zones of interest that were less than 10 m apart and retained the integrity of the seal throughout the high-pressure stimulation operation. Well is open to production without any annular pressure, thus, saving the operator's time and cost on the remedial cementing operations. The proposed solution will help operators to ensure long-term zonal isolation in the HTHP wells which are subjected to dynamic pressure and temperature changes in the post slurry placement phase. The operators can also avoid the time and money on expensive remedial operations.

Abstract Permeability prediction is an important step in reservoir characterization for effective modeling of water-flood performance and subsequent EOR processes. Permeability should be determined accurately versus depth in all cored and logged wells in a field. This is normally achieved by the use of cross-plots of core permeability versus core porosity from log-derived porosity in un-cored wells. The main aim of this research is to use X-ray CT images of reservoir cores to identify geological textures and predict permeability based on well-established models in carbonates. Full-diameter reservoir cores were imaged using dual energy X-ray CT. Porosity logs were derived along the entire cores from the dual energy data. Textural variations were identified from the appearance of the CT images. Statistical sample selection was designed to honor the distribution of porosity and CT-textures. Porosity-permeability correlations were established in the texture domain using plug-scale poroperm data and thin-section photomicrograph analysis. Plug-scale geological analysis confirmed the CT textures in the images, which allowed the derivation of texture logs along the cores. The porosity and permeability data were fitted into unique trends that were derived from the detailed textural analysis. This process provided the link between the poroperm trends and the different textures in the core enabling permeability to be predicted along the entire whole core intervals. This paper describes a novel approach of combining textures with porosity to model permeability along the reservoir column. A unique dual energy CT technique was used to ensure that all the core property variations were well represented in the plug-scale core analysis measurements. This analysis will open the way for predicting permeability in un-cored wells using texture information from down-hole image logs. In the future, machine-learning algorithms will be employed following the same workflow for effective permeability prediction in the field.

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 This study attempts to describe and model the process leading to the genesis of the tilted oil-water contact (OWC) observed in the lower part of the Thamama Group in an offshore Abu Dhabi field. Post-oil-migration deformation is thought to be the mechanism that produced a tilted OWC dipping towards the Northeast. Deciphering the tectonic evolution from Jurassic to Paleocene times confirms a long and complex structural history combining burial, halokinesis, uplift and tilting. Diapiric activity was probably established in the eastern accumulation by pre-Jurassic times, followed by localized salt-related doming in both parts of the field. During the mid-Eocene occurred a late tilting of the northeastern part of the field, enhancing the curvature of the area. This late tilting caused oil saturation redistribution. In uplifted areas of the field, water saturationdecreased along the drainage curve whereas in areas brought structurally closer to the Free Water Level (FWL), water saturation increased along a scanned imbibition curve. The objective of this study is to retrace the saturation history of the field using lab-measured bounding capillary pressures. This workflow ensures the correct initialization of the dynamic reservoir model and reproduces the observed field behavior. Drainage and imbibition capillary pressures are available for different rock types (RT), measured under various experimental set-ups (mercury injection, porous plate, centrifuge). This study reconciles lab measurements with wireline logs and Dean-Stark data to produce a representative capillary pressure curve for each RT. Next, the structural deformation history is representedas a series of elementary geometric transformations (localized subsidence and global translation) to restore the reservoir in its pre-deformation state. Wireline log saturationsare matched to capillary-based water saturations by adjusting the present day free water level (FWL) and the change of FWL due to seepage. The dynamic model is then initialized by enumeration with the original water saturation and let to equilibrate for 40,000 years. The fluid redistribution and pressures are then monitored to confirm that equilibrium has been attained. This equilibration step ensures that the fluids are at their correctstate of relative permeability and capillary pressure at the start of simulation, something that is not garanteed in the case of direct enumeration of the final saturations. The implications of such procedure on the dynamic behaviorare explored by simulating 50 years of production history and compa. This study greatly improved the saturation modelling by moving from synthetic porosity-bin functions to physics and texture based capillary pressures. The proposed workflow enhanced the history-match quality and reproduced observed field behaviors such as the high water-cut development in the Northeast. A tilted OWC might increase the in-place however extracting those resources might prove more challenging in the face of the low oil mobility. The oil below OWC might not be recovered under conventional waterflood methods and would warrant an EOR implementation. In the future, an appraisal well is planned in the Northeast to assess the volume and mobility of the oil below OWC. It is the first time an integrated workflow, combining SCAL and structural geology, is proposed to correctly initialize the dynamic model for reservoirs that experienced a post-migration deformation, hence making the present study unique.

Abstract The selection of proppants is quite a challenging task as the cost almost comprises 20% to well over 50% of total fracturing jobs when ceramic is used. So, in the current situation of oil price crises, optimizing the proppant cost in Pakistan, where fracturing cost is twice as compared to the United States of America, not only provide better-optimized stimulation but also maximizes the Net Present Value. The objective of this study constitutes of two: firstly, to investigate the various types of proppants for peerless fracture parameters based on the post-frac results by using the FracCade simulator. Secondly, to evaluate the Net Present Value and select the most effective proppant based on the Net Present Value. In this case study, the research is conducted on scrutinization of proppant discretion based on net present value, the reservoir data under the study is real-time data of x-well of Tobra formation. The average permeability of the formation is 1md. The focus of this project is to investigate the effects and potential of 25 proppants on hydraulic fracturing treatment. Prior to the selection of the proppants for the evaluation of NPV, sensitivity analysis is done based on closure stress and fracture parameters to screen out 20 proppants. The final selection of proppant is made on the Net Present Value (NPV) which will decide which proppant will give the economic edge to the fracturing treatment. The result of the study is based on the investigation of 25 proppants based on the Net Present Value (NPV) of the fracturing treatment. Before the selection of the proppants for the evaluation of NPV. Almost 20 proppants have been screened out based on the closure stress and fracture parameters. Finally, 5 proppants after technical scrutinization are selected for the evaluation of NPV. From 17 proppants, 5 proppants are selected based on fracture conductivity. These are selected for the evaluation of NPV. Among the 25 proppants, proppant which gives the highest Net Present Value (NPV) is Sintered Bauxite which enhances the well productivity up to 3.5 times and gives the Net Present Value (NPV) of $12,548,762.98.

Abstract The shale revolution has extended the life cycle of the oil and gas industry, promoted the growth of global oil and gas reserves and production, and changed the energy's strategic pattern of various countries. At present, the national shale-gas demonstration area of PetroChina Changning and Weiyuan is in the stage of large-scale production. Horizontal well and hydraulic fracturing are two key technology that have proven to provide an effective way to economically develop medium to high maturity shale gas resources. However, due to geological complexity of the shale-gas demonstration area, and the lack of robust analysis and research on overpressure mechanism and wellbore instability characteristics, drilling events such as stuck pipes, lost circulations and inflows occurred frequently during horizontal well drilling. These non-productive events greatly restricts the wellbore construction cycle time and the production of shale gas reservoir. A comprehensive geomechanical study was carried out from which the three pressure profiles required for drilling, i.e., pore pressure, collapse pressure and fracture gradient, are established. The study also clarified the spatial distribution of overpressure across the field. The improved pore pressure and geomechanical understanding of the field provides the necessary inputs for an integrated, multi-disciplinary approach carried out during pre-drilled analyses, real-time monitoring and post-drilled evaluation to manage the stability of horizontal wells. The safe mud weight window derived from geomechanics provides the basis for mud weight and mud formulation designs that can be continuously optimized to improve wellbore stability and reduce drilling risks. The integrated approach has been applied for 4 horizontal wells in Weiyuan's shale gas field. One of the wells, Wei202-H34-3, has the horizontal section length of 2500m, making it the longest horizontal section recorded in the block. Drilling performance analyses of the well showed that the overall drilling risk, the wellbore construction time, and the drilling costs were substantially reduced by optimizing the drilling operations through geomechanics integrations and applications. The experience and knowledge obtained from this integrated workflow will provide guidance and serve as reference for the efficient development of unconventional oil and gas reservoirs in China.