Day 1 Mon, March 21, 2022最新文献

{"title":"Dynamic Data Integration in Dual-Porosity Dual-Permeability Reservoirs: Permeability Conditioning Perspective","authors":"A. Alramadhan, S. Lyngra","doi":"10.2118/200258-ms","DOIUrl":"https://doi.org/10.2118/200258-ms","url":null,"abstract":"\u0000 Advancements in pore-scale and core-scale studies have provided an improved understanding of the micro- and macro-porosity nature of carbonate rocks and how the two systems interact. The interaction of the two systems in the presence of a third (fracture) and fourth component (vugs) has not been fully investigated in the industry. This paper demonstrates applicability and some limitations of permeability conditioning practices in dual-porosity dual-permeability (DPDP) systems. In addition, this work demonstrates how the permeability conditioning process can be used as a tool for dynamic classification and calibration of extreme permeability (super-k) intervals in dual-permeability systems.\u0000 A highly scalable parallel DPDP finite difference simulator is used to: Firstly, demonstrate the permeability conditioning process and how it impacts reservoir dynamics. Secondly, present cases where flowmeter (PLT) responses show a limitation in characterizing super-k intervals and its impact. Thirdly, demonstrate the role of enhancement factor in representing flood front movement for multiple super-k dominated reservoir realizations constrained by flowmeter and pressure transient permeability-thickness controls.\u0000 The results of this work expands on the representation of super-k intervals in dual-permeability systems in three main areas. Firstly, the decision to explicitly model super-k intervals as a fractured media or to implicitly model these features as a matrix permeability enhancement should be evaluated with use of enhancement factor combined with water breakthrough trends observed in the field. Secondly, the use of PLT responses to characterize super-k intervals should be made after careful evaluation of their responses before and after any well intervention. This step is crucial for proper permeability conditioning and in capturing reservoir dynamics of masked high flow intervals, i.e., new flow dominating features that appear only after the original super-k intervals have been plugged. Thirdly, as part of the integration of pressure transient results into a DPDP finite difference model, special consideration is needed for wells with a non-intersecting conductive fracture signature due to a limitation in the Peaceman formulation for DPDP reservoirs, which only considers cells intersecting the well for productivity index and PLT response calculations.\u0000 In summary, this paper provides guidance for geologists and reservoir engineers, through use of a permeability conditioning process, to dynamically classify and calibrate fractured/super-k intervals during the process of constructing full-field dual-porosity dual-permeability reservoir simulation models.","PeriodicalId":11113,"journal":{"name":"Day 1 Mon, March 21, 2022","volume":"15 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"88022396","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Leveraging 3D High Resolution PSDM Data Volumes for Early Geohazard Detection","authors":"D. Lagomarsino, Matteo Fornari, C. Barbieri, T. Ciccarone, Alessandro Lomartire, E. Norelli, D. Rosa","doi":"10.2118/200062-ms","DOIUrl":"https://doi.org/10.2118/200062-ms","url":null,"abstract":"\u0000 The exploiting of High Resolution (HR) Pre Stack Depth Migration (PSDM) 3D seismic volumes, normally used for Oil & Gas exploration, has been pushed forward in geomorphological and geohazard risk evaluation. The novel approach proposed here allows to carry out such activities very early in respect of the standard work flow. Early awareness of critical areas turns out to be crucial in fast-tracking projects and allows a design to cost optimization.\u0000 The 3D HR PSDM outputs are processed in order to generate a detailed imaging of the shallower portion of the seismic volumes. The volumes are processed at a 2 meters depth interval and converted in time (DTT). Finally, a dedicated post migration time processing sequence, followed by time-to-depth conversion, is applied to generate a Higher Resolution Volume (HRV) in depth domain. The resulting 3D volume is then analyzed to study the seabed and the sub-bottom from a geomorphological standpoint. The analyses focus on the identification and mapping of the distribution of the \"areas of instability\" eventually classified according to a specific KPI (Safety Factor Index in static conditions), providing a quantitative slope stability assessment of the area.\u0000 The new approach has been validated comparing the DTM (Digital Topographic Model) derived from the 3D HR PSDM volume and the available MBES (Multi Beam Echo Sounder) bathymetry.\u0000 The proposed approach leads to a dramatic improvement in the detection capability, highlighting the major critical structures such as: canyon flanks, buried slides, creeps and tension cracks on the shelf break, boulders and compacted sediments, sediment banks and sediment waves reshaped by bottom currents, pockmark areas and fluid escapes, turbidity mass movements and furrows due to tectonic activities. The approach matches perfectly the detection capability of a traditional MBES approach.\u0000 The described workflow is potentially highly beneficial for early de-risking assets and operations, especially for facilities installation. The proposed innovative approach allows a detailed planning of dedicated data acquisition campaigns, restricted to the most critical areas, with a tangible reduction in the turnaround times and cost savings crucial for project economics.","PeriodicalId":11113,"journal":{"name":"Day 1 Mon, March 21, 2022","volume":"12 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"89069492","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"X-Ray Computed Tomography Assisted Investigation of Flow Behaviour of Miscible CO2 to Enhance Oil Recovery in Layered Sandstone Porous Media","authors":"Duraid Al-Bayati, A. Saeedi, Ipek Ktao, M. Myers, C. White, A. Mousavi, Q. Xie, C. Lagat","doi":"10.2118/200103-ms","DOIUrl":"https://doi.org/10.2118/200103-ms","url":null,"abstract":"\u0000 Reservoir heterogeneity reflected by permeability variation in the vertical direction is expected to significantly impact on the subsurface multiphase flow behaviour. In this context, we have shown previously that during immiscible flooding the crossflow between low and high permeability zones plays a significant role in determining the reservoir performance in terms of the hydrocarbon yield. In this manuscript, the contribution of crossflow to oil recovery in layered sandstone porous media during miscible CO2 flooding is explored. We conducted core flooding experiments using a core sample constructed by attaching two axially split half sandstone plugs each with a different permeability (0.008 and 0.1 (μm)2). The crossflow between the two layers was controlled by placing either a lint-free tissue paper or an impermeable Teflon sheet to represent a layered heterogeneity with and without communication, respectively. Additionally, to better understand the underpinning mechanisms influencing the flood performance, we imaged the samples during flooding using a high-resolution medical X-Ray computed tomography (XCT) scanner.\u0000 Our results show that core-scale heterogeneity would indeed play an important role in determining the spatial distribution of the injected CO2during miscible flooding, consequently the oil recovery factor. For instance, our results confirm that permeability heterogeneity in vertical direction would lead to CO2 establishing a prefrential flow path through the high permeability layer leading to its early breakthrough. The above-mentioned CO2 channeling is clearly evident from the X-ray images captured during flooding. However, a reasonble amount of CO2 would still enter the low permeability layer contributing positively to the ultimate oil recovery factor. In fact, the post-processing of the XCT data confirmed the above to take place when cross-layer communication was allowed. The diversion of CO2 from the high to low permeablity layer is believed to be due to the crossflow phenomenon (induced by the viscous and dispersion forces) resulting in a subtle increase (i.e. 1.7%) in the ultimate oil recovery. In a similar study we have done about immiscible flooding, the contribution of crossflow to the overall recovery was found to be about 5%. The less pronounced effect of crossflow under miscible conditions is believed to be due to the absence of capillarity as a more effective driving force behind crossflow. To the best of our knowledge, our core-flooding results as presented in this manuscript and backed by X-ray CT visualisation, are the first set of their kind. They are insightful and would be of interest to the scientific community in revealing how crossflow may control flow behaviour in heterogeneous sandstone reservoirs, with important implications for numerical modelling of CO2 injection.","PeriodicalId":11113,"journal":{"name":"Day 1 Mon, March 21, 2022","volume":"36 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"80533253","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Water Injectivity Decline in an Omani Oil Field: Possible Causes and Mitigation","authors":"Ibtisam Al-Shabibi, J. Naser, R. Al-Maamari, M. Karimi, A. Al-Salmi, Hajir Al-Qassabi","doi":"10.2118/200225-ms","DOIUrl":"https://doi.org/10.2118/200225-ms","url":null,"abstract":"\u0000 Treated oilfield produced water is injected into reservoirs to increase the depleted reservoir pressure and enhance oil recovery. The main challenges in this process are injectivity decline and high tubing head pressure (THP) which is most often caused by the deterioration in the reservoir permeability.\u0000 This investigation focuses on identifying root causes behind injectivity decline in a sandstone reservoir in Oman. Acid stimulation has been applied to improve the reservoir permeability, but it turned out to be non-feasible due to frequency of such interventions and high associated costs. Several factors, such as injection water quality and reservoir mineralogy, can adversely affect the reservoir permeability and cause injectivity decline. Various approaches to tackle this problem have been adopted in this study including; water analysis, scale modeling, formation damage simulation and core flooding experiments.\u0000 The scale modeling results showed compatibility between formation and injection water where the scaling potential for both barium sulphate (BaSO4) and calcium carbonate (CaCO3) scales were unlikely to form at reservoir conditions. Injection water analysis showed that, in some cases total suspended solids and oil content exceeded the recommended limit, which might contribute to reservoir permeability decline. XRD analysis of the reservoir core samples revealed that fines and expansive clays are the main components. The core flooding experiments demonstrated that reservoir pore throats get plugged due to two main factors; the suspended solid particles present in the injected water and swelling clays present in reservoir core samples. The formation damage simulator showed that fines migration and clay swelling are the two main possible formation damage mechanisms. To enhance the water injectivity process, the use of a clay swelling inhibitor along with a filtration system to remove suspended particles in the injected water are recommended for the reservoir studied.","PeriodicalId":11113,"journal":{"name":"Day 1 Mon, March 21, 2022","volume":"54 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"83428817","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Fluidic Diode Autonomous ICD Selection Criteria, Design Methodology, and Performance Analysis for Multiple Completion Designs: Case Studies","authors":"Tejas Kalyani, G. Corona, Kevin Ross","doi":"10.2118/200255-ms","DOIUrl":"https://doi.org/10.2118/200255-ms","url":null,"abstract":"\u0000 Inflow control device (ICD) technology helps in balancing the production across the entire interval, addressing some of the challenges associated with horizontal and deviated wells. Nevertheless, ICDs have limited capabilities in identifying and restricting unwanted fluids upon breakthrough. Autonomous ICD (AICD) technology functions similar to an ICD initially (i.e., balancing flux across the length of horizontal wells, effectively delaying breakthrough) but has the additional benefit of restricting the flow of unwanted fluids upon breakthrough. Multiple AICD case histories highlighting the benefit of the technology in mitigating well performance challenges and delivering improved recovery throughout the life of the well are discussed.\u0000 AICD technology is fluid dependent, principally reacting to the properties of the fluid flowing through it and creating an additional pressure drop to restrict the production of unwanted fluids. The fluidic diode-type AICD has no moving parts and uses flow dynamic properties to distinguish between the fluids. It uses downhole fluid properties to accurately differentiate between oil, water, and gas; and changes the flow path autonomously to restrict unwanted fluids upon breakthrough; and uplifts oil production from the oil-saturated zones across the wellbore.\u0000 Extensive testing has been completed to characterize and accurately predict the flow performance, which enables designing an AICD completion efficiently. Flow performance analysis of the various types of fluidic diode AICDs designed to address various well performance challenges [i.e., high gas-oil ratio (GOR) or high water production or both, increasing oil production] is discussed. The flow performance analysis has been derived using extensive and rigorous single-phase and multiphase flow-loop test programs, covering the wide range of oil properties.\u0000 This paper will also highlight the screening criteria in selecting a candidate well for fluidic diode AICDs application. Furthermore, the paper will also discuss in detail a reservoir-focused well-centric completion design workflow for designing fluidic diode-type AICD completions for a candidate well. This collaborative workflow takes into account the various subsurface and well attributes to meet or exceed well key performance indicators (KPIs) over the life of the well.\u0000 It can be observed from the results of various field installations and production data analysis that installing AICDs during the early life of wells or fields results in a higher ultimate recovery (UR) compared to installing it in brown or matured fields. However, the recovery with AICD in brown/matured fields can be higher than ICD or any other legacy openhole completion.\u0000 The fluidic diode AICD design methodology and field installation results for AICD technology in different completion designs, such as openhole gravel pack, open hole, retrofit, artificial lift completion, and multilateral wells, are discussed as well. Additionally, it","PeriodicalId":11113,"journal":{"name":"Day 1 Mon, March 21, 2022","volume":"74 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"80896906","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Optimizing Ongoing Field Scale Polymer Flood in South of Oman Through Detailed Simulation","authors":"A. Anand, O. Riyami","doi":"10.2118/200207-ms","DOIUrl":"https://doi.org/10.2118/200207-ms","url":null,"abstract":"\u0000 Polymer flood (PF) applications have increasingly been extended to medium-to-heavy oil reservoirs for enhanced displacement and sweep efficiency and pushing the recovery beyond the limits of conventional recovery techniques. The relatively low carbon footprint and gas-light nature has made PF attractive in many cases compared to the traditional thermal methods. Consequently, many fields in the Sultanate of Oman with viscosities ranging from about 90cP to 500cP have been studied and field trialled for polymer development, and one such field has been successfully undergoing field-scale PF for over 8 years, which is the subject of this study.\u0000 As PF is matured in the field, the ongoing challenge is to support production operations and optimise flood performance.\u0000 This study lays the foundation for holistic simulation study targeting theoretical based considerations for PF optimization. It starts with understanding the nature of polymer/polymer and polymer/water type displacements and stabilities, and encompasses modelling the phenomena of viscous fingering/instabilities in a range of model set-ups, starting from high resolution core-scale 2D models to 3D sector models incorporating varying degrees of geological heterogeneities.\u0000 Understanding of displacement stability gained with high-resolution models is extended to investigate polymer/water mixing, Water-Alternating-Polymer (WAP) recovery and polymer grading (tapering). These subjects have been integrated to emphasise the optimal polymer slug size requirement with creaming curve analyses that build on the principles of containing fingers/instabilities due to lower viscosity follow-up slugs or chase water.\u0000 The polymer flood optimization is taken to the next step by investigating the concepts of polymer grading. Three prevalent grading concepts proposed by Claridge ([5], [6], [7], [8]), Ligthelm-Schulte and Stegemeier in combination with different mixing rules form the basis of polymer grading assessment.\u0000 The study highlights significant scope for optimizing polymer flood in the field both in terms of long-term improved recovery performance at reduced cost as well as tackling the short-term operational challenges, potentially impacting the business bottom-line.","PeriodicalId":11113,"journal":{"name":"Day 1 Mon, March 21, 2022","volume":"13 1 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"79487284","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"The Role of Polymer on Surfactant-Foam Stability During Carbon Dioxide Mobility Control Process","authors":"Z. Alyousef, Othman Swaie, A. Alabdulwahab, S. Kokal","doi":"10.2118/200125-ms","DOIUrl":"https://doi.org/10.2118/200125-ms","url":null,"abstract":"\u0000 The in-situ generation of foam is one of the most promising techniques to solve gas mobility challenges in petroleum reservoirs and subsequently improve the volumetric sweep efficiency. The stabilization of foam at reservoir conditions is a major challenge. The harsh reservoir conditions, such as high temperature, high brine salinity, together with surfactant adsorption on the rock may result in unstable foam and, consequently, poor sweep efficiency. Foam additives, such as polymers, might help strengthen the physical properties of foam film and improve foam stability. This work evaluates the effectiveness of a polymer on enhancing CO2-foam stabilization at harsh reservoir conditions.\u0000 Static and dynamic foam tests were conducted to evaluate the role of polymer on foam stability. Three foaming surfactants were used to assess the ability of the polymer on enhancing foam stabilization. The static foam tests were conducted at conditions similar to reservoir conditions using test tubes. Foam column, and foam life were measured to evaluate the role of the polymer on foam stabilization. Foam viscosity in absence and presence of the polymer was measured using foam rheometer apparatus. The dynamic foam tests were conducted to assess the ability of tested materials to generate viscous foams and also measure the CO2 mobility in porous media using a coreflooding system. The mobility reduction factor (MRF) was measured at high pressure and high temperature (HPHT) conditions, 3200 psi and 100°C.\u0000 The static foam tests and foam rheology measurements indicated that the addition of the polymer enhanced foam stability as a result of increasing the bulk viscosity of the aqueous solutions. The results found that the foam life increased with the polymer concentration. However, the increase of polymer concentration makes the solution very viscous, hence, the foam generation becomes challenging. The dynamic foam tests showed that the foam generated in absence of the polymer was able to reduce the CO2 mobility 13 fold. However, the addition of the polymer resulted in higher pressure drops during CO2 floods, more resistance to gas flow and, therefore, lower gas mobility compared to that obtained with surfactant alone. The addition of the polymer reduced the CO2 mobility 50 fold. This higher reduction in the CO2 mobility as a result of adding the polymer can be attributed to the effectiveness of the polymer in improving the foam stabilization and prolong the life of generated foam.","PeriodicalId":11113,"journal":{"name":"Day 1 Mon, March 21, 2022","volume":"29 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"85274204","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Improving Uptime of Sandy Wells with PCPs Through the Application of Self-Optimization Routines","authors":"Conny Velazco-Quesada, Luis Vargas, M. Sawafi, A. Busaidi, Hilal Mamari, A. Yahyai, K. Woolsey, B. Montilla","doi":"10.2118/200211-ms","DOIUrl":"https://doi.org/10.2118/200211-ms","url":null,"abstract":"\u0000 A field trial has been completed in five oil producing wells, completed with progressive cavity pump (PCP) and under sand co-production scheme with the following objectives: Increasing well uptime by eliminating rotor stuck events and extending time between failures,Reducing locked-in potential associated to slow ramp-up process from initial to target offtake,Reducing the need for operator visits to start or adjust well running conditions after station trips,\u0000 To achieve this, four wells with very premature failures (less than 6-months) were selected for the trial. One fifth well with high level of depletion was also selected. The target for this last application was to check the impact of reducing fluid level safety factor on pump performance.\u0000 In all wells, PCP well controllers were installed with self-optimization routines that maintained safe fluid levels above the pump intake while adjusting speed for potential sand ingress. Speed ramp-up time was programmed for completion within two days of start up.\u0000 First, realtime signals were enhanced to monitor all well parameters that could affect performance, such as tubing head pressure (THP) and casing head pressure (CHP). This information was key to manage the actual fluid levels above the pump, even in gassy wells, allowing safety factors to be reduced by 50% without affecting pump performance.\u0000 Increase in pump run life by 40 to 140% was observed in the four sandy wells selected. No well interventions were required for sand flushing. Ramp-up time was successfully completed within a day of start-up and after two days production at target was stabilized.\u0000 After trips, it was found that the well started without the need for operators, as long as power supply was restored. Operator visits were only required for power or signal issues to be fixed, but well was safely kept optimized within those periods.\u0000 Estimated oil production availability increase from this trial is 12% per well per year.\u0000 This paper presents the main learnings from applying a self-optimization routine in 5 sandy wells and what is important to consider to achieve cost reduction, increase in well uptime and to reduce the need for manual adjustments/field visits.","PeriodicalId":11113,"journal":{"name":"Day 1 Mon, March 21, 2022","volume":"26 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"84886812","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Artificial-Intelligence Based Horizontal Well Placement Optimization Leveraging Geological and Engineering Attributes, and Expert-Based Workflows","authors":"Lichi Deng, A. Salehi, Wassim Benhallam, H. Darabi, D. Castineira","doi":"10.2118/200069-ms","DOIUrl":"https://doi.org/10.2118/200069-ms","url":null,"abstract":"\u0000 Horizontal wells provide a highly efficient way to maximize contact with the reservoir target and to increase overall recovery by allowing a larger drainage pattern. Traditionally, the identification of optimal horizontal well locations involves domain expertise across multiple disciplines and takes a long time to complete. In this work, a fully streamlined artificial intelligence (AI)-based workflow is introduced to facilitate horizontal opportunity identification by combining geological and engineering attributes in all types of reservoirs.\u0000 This workflow relies on automated geologic and engineering workflows to map the remaining oil in place and identify areas with high probability of success (POS) and high productivity potential. Advanced computational algorithms are implemented under a variety of physical constraints to identify best segments for placing the wellbores. Statistical and machine learning techniques are combined to assess neighborhood performance and geologic risks, along with forecasting the future production performance of the proposed targets. Finally, a comprehensive vetting and sorting framework is presented to ensure the final set of identified opportunities are feasible for the field development plan. The workflow incorporates multiple configuration and trajectory constraints for the horizontal wells’ placement, such as length/azimuth/inclination range, zone-crossing, fault-avoidance, etc. The optimization engine is initialized with an ensemble of initial guesses generated with Latin-Hypercube Sampling (LHS) to ensure all regions of good POS distribution in the model are evenly considered. The intelligent mapping between discrete grid indexing and continuous spatial coordinates greatly reduced the timing and computational resources required for the optimization, thus enabling a fast determination of target segments for multi- million-cell models. The optimization algorithm identifies potential target locations with 3D pay tracking globally, and the segments are further optimized using an interference analysis that selects the best set of non-interfering targets to maximize production. This framework has been successfully applied to multiple giant mature assets in the Middle East, North and South America, with massive dataset and complexity, and in situations where static and dynamic reservoir models are unavailable, partially available, or are out of date. In the specific case study presented here, the workflow is applied to a giant field in the Middle East where tens of deviated or horizontal opportunities are initially identified and vetted.\u0000 The methodology presented turns the traditional labor-intensive task of horizontal target identification into an intelligently automated workflow with high accuracy. The implemented optimization engine, along with other features highlighted within, has enabled a lightning-fast, highly customizable workflow to identify initial opportunity inventory under high geological complexity","PeriodicalId":11113,"journal":{"name":"Day 1 Mon, March 21, 2022","volume":"18 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"76576319","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Sultanate of Oman Giant Fractured Carbonate Field, Fracture Model Impact on Understanding Field Connectivity from Seismic to Flow","authors":"Mohmed Helmy, R. Farajzadeh, Adnan Al Maqbali, Mohamed Sabahi","doi":"10.2118/200154-ms","DOIUrl":"https://doi.org/10.2118/200154-ms","url":null,"abstract":"\u0000 The paper presents an integrated reservoir modeling (IRM) of a giant complex fractured carbonate reservoir to get insights about the reservoir's displacement process. Historically the field has undergone many recovery mechanisms, nowadays two still remains: Gas-Oil Gravity Drainage (GOGD) and waterflood. A major change in understanding the vertical connectivity of the different reservoir units henders the future development options. A decision-based approach was followed to select an economically feasible field development option. Selection of economically feasible development option need; field performance review, full frame structure and geological model is built, ideal conceptual sector models sliced from the full frame structural model and numerical dynamic simulation is carried out with different development options (water injection (WI), gas oil gravity drainage (GOGD) and mixture of WI and GOGD).\u0000 Understanding the fluid flow behavior in fractured carbonate reservoirs is complex and challenging. The complexity directly linked to the understanding of the fracture hierarchy and connectivity. The field development plan at the time of analyzing the field data was water injection with very good recovery factor that cannot be explained by the injected water pore volume. Applying the integrated reservoir modeling (IRM) procedures, full filed performance review is carried out, update of subsurface models with different fracture model realizations and run numerical dynamic simulations over idealized conceptual models with different development options. Full filed history match is carried out on the selected development option.\u0000 Front Loading and data analysis is key for successful modeling strategy, the main uncertainty is the fracture distribution, better understanding of the reservoir units cross flow, understand the effect of different development options on recovery factor in significantly short time and create reasonable scenarios of subsurface.\u0000 Well performance showed some effects of water injection. Gas oil gravity is the dominant recovery process. Gas recirculation of shallow wells have negative effects on the GOGD process. Adding water injectors with continuous gas injection has negative effects on the recovery factor.\u0000 The fracture hierarchy is key to understand the subsurface. All the studied reservoir units are in communication via fracture corridors. The main recovery mechanism is gas oil gravity drainage (GOGD). WI may have local effects but as development concept it will not add value. Well location relative to fracture corridors is critical to achieve better history match. Water injection has negative effect on field recovery and operationally (WRFM). Filed operation optimization (optimize gas injection) can result in maintain the same rate with lower CPEX and OPEX (Capital spending efficiency).\u0000 This paper presents significant importance understanding the integration and clear vision of the modeling strategy that saves effort an","PeriodicalId":11113,"journal":{"name":"Day 1 Mon, March 21, 2022","volume":"2 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"82148849","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}