In 2015-2016, the Alkaline-Surfactant-Polymer (ASP) flood Pilot in Marmul was successfully completed with ∼30% incremental oil recovery and no significant operational issues. In parallel to the ASP pilot, several laboratory studies were executed to identify an alternative and cost-efficient ASP formulation with simpler logistics. The studies resulted in a new formulation based on mono-ethanolamine (MEA) as alkali and a blend of commercially available and cheaper surfactants. To expediate the phased full field development, Phase-1 project was started in 2019 with the following main objectives are confirm high oil recovery efficiency of the new ASP formulation and ensure the scalability and further commercial maturation of ASP technology; de-risk the injectivity of new formulation; and de-risk oil-water separation in the presence of produced ASP chemicals. The Phase 1 project was executed in the same well pattern as the Pilot, but at a different reservoir unit that is more heterogeneous and has a smaller pore volume (PV) than those of the Pilot. This set-up allowed comparing the performance of ASP formulations and taking advantage of the existing surface facilities, thus reducing the project cost. The project was successfully finished in December 2020, and the following major conclusions were made: (1) with the estimated incremental recovery of around 15-18% and one of the producers exhibiting water cut reversal of more than 30%, the new ASP formulation is efficient and will be used in the follow-up phased commercial ASP projects; (2) the injectivity was sustained throughout the entire operations within the target rate and below the fracture pressure; (3) produced oil quality met the export requirements and a significant amount of oil-water separation data was collected. With confirmed high oil recovery efficiency for the cheaper and more convenient ASP formulation, the success of ASP flooding in the Phase-1 project paves the way for the subsequent commercial-scale ASP projects in the Sultanate of Oman.

A new integrated growth strategy of an oil & gas company is focusing on maximizing the value of reserves and production in order to meet the value proposition of the highest possible return to the company. The strategy is built on the strategic foundation of the company of People, Performance, Profitability and Efficiency. From a business performance perspective, the strategy will bear fruit through increased production capacity, improved operational and cost efficiencies, re-energizing mature fields and uncovering new resources whilst maintaining safety and asset integrity. The objective of this global level exercise aims to assess and evaluate various Digital Oilfield (DOF) practices and initiatives against industry best practices, to perform a landscape assessment of the upstream assets, to review the asset digital gap, to develop a strategic framework and roadmap ensuring that the company strategic pillars are supported across all relevant aspects, by closing the digital gap between current and future states. The assessment scope covers the following domains: Reservoir management Production optimisation Operation management & integrity Engineering & projects Drilling Efficiency Logistics & Planning The landscape assessment and gap analysis consist of several stages that starts from documenting the information received from the assets capturing their current business practices and processes, analyzing the "as-is" condition, designing the future state, assessing the impact to the specific assets, define the benefits and value and creating a 5-year business roadmap. Aligned with the company DOF strategy, understanding the asset digital gap and enhancing the asset digital maturity will improve: HSE and asset integrity by reducing hazard exposure, optimizing energy usage and improving wells and facilities integrity Collaboration and faster analysis leading to timely decision making Integrated operations by optimized drilling planning, operations, optimized production forecasting and integrated planning Optimum Reservoir Management through enhanced reservoir surveillance and recovery

Geosteering is an important area and its quality determines the efficiency of formation drilling by horizontal wells, which directly affects the project NPV. This paper presents the automated geosteering optimization platform which is based on live well data. The platform implements online corrections of the geological model and forecasts well performance from the target reservoir. The system prepares recommendations of the best reservoir production interval and the direction for horizontal well placements based on reservoir performance analytics. This paper describes the stages of developing a comprehensive system using machine-learning methods, which allows multivariate calculations to refine and predict the geological model. Based on the calculations, a search for the optimal location of a horizontal well to maximize production is carried out. The approach realized in the work takes into account many factors (some specific features of geological structure, history of field development, wells interference, etc.) and can offer optimum horizontal well placement options without performing full-scale or sector hydrodynamic simulation. Machine learning methods (based on decision trees and neural networks) and target function optimization methods are used for geological model refinement and forecasting as well as for selection of optimum interval of well placement. As the result of researches we have developed the complex system including modules of data verification and preprocessing, automatic inter-well correlation, optimization and target interval selection. The system was tested while drilling hydrocarbons in the Western Siberian fields, where the developed approach showed efficiency.

Lapa is a pre-salt deep-water field located around 270km off the coast of São Paulo, Brazil at Santos basin. This carbonate reservoir lies in water depths of around 2,100m and can produce good quality light 26° API oil. The stimulation in large carbonate reservoirs is very challenging, and techniques used for Lapa were based on chemical divergence. The development in offshore environments requires proper planning, execution, and monitoring to achieve the desired results and, of course, profitability. The matrix acidizing method was chosen to stimulate all wells of this campaign (2 producers and 2 injectors). This method consists of bypassing formation damage and stimulating the reservoir by creating wormholes via chemical pumping. In the design phase, stimulation operations previously performed at this field were reviewed, analyzed, and optimized. The main changes were regarding the completion strategy without the use of coiled tubing and placement during the completion phase as it could optimize the time and the cost for the project. The volumetric rate (gal/ft) was also reduced and the selection of the main fluid changed after several laboratory analysis and software simulations. The Lapa field requires high fluid volumes due to the length of the intended treatment interval. The assembly of a stimulation plant on a supply vessel from operator fleet (multi-purpose FSV – field support vessel) was the most cost-efficient approach to address the high volumes required as there was no Well Stimulation Vessel (WSV) available "on call" in the Brazilian offshore market at that time. This solution could also optimize the vessel fleet while the vessel was not required for pumping as FSV was also equipped with ROV and was mean to carry subsea planned task. The fluid test strategy was also a key point for this successful project as many tests were performed to make sure that the correct fluid system was selected. During this process, several fluid systems and different formulations were submitted for core flow tests and dual core flow tests to evaluate worm holing efficiency of retarded fluids and diversion performance of Chemical diverters. Compatibility tests were also performed, and a mud cake breaker was developed locally, especially for this project. This paper will bring an overview of all aspects regarding Lapa stimulation project since the conception, fluid system selection, laboratory tests, lessons learned and the potentially future strategy for this field.

When inadequate information appears via a long-winded channel, project leaders usually struggle to make timely decisions. There is frequently a lack of visibility, contractual and organizational fragmentation, and genuine facts being segregated and concealed due to an optimism bias. Despite the finest planning and estimation efforts, projects frequently exceed their budgets or experience delays of more than 30%. The paper outlines the importance of data and of data use to improve the performance in projects planning and delivery . The data value and hierarchy are reviewed in the context of the construction industry and the importance of a smooth digitalization process for ensuring acceptance and adoption is discussed. The concept of ‘ digital construction blocks’ TM and Lean thinking is introduced to address the problem of complexity which is commonly recognized as the main cause of cost overruns, time delays, and poor quality and safety for the construction industry. To capture the footprint of how the asset was built, the authors propose the Digital Twin of Execution adding dynamism to the commonly discussed Digital Twin of Asset , which is more static when the asset has already been constructed. The project is organized into digital blocks, allowing all project functions and disciplines to focus on a common path of construction , allowing for an earlier start of a constraint-free construction and, as a result, de-risking and compressing the total execution schedule. Data from existing systems and technologies is unlocked and placed in automated processes , allowing thousands of documents, activities, and fast-moving events to be collected in digital blocks of construction. The digital block is connected throughout project stages and taken across all aspects of the project, including plot plans, activity plans, drawings, 3D, materials, and so on, resolving the project's disarray caused by manual and analogue procedures. The entire planning, project setup, and execution process is aided by GIS, which provides visibility at various levels of magnification via an interactive geo spatial map superimposed with plot plans, timetables, and work packages. Artificial intelligence (AI) and machine learning (ML ) can be used to forecast the probability of danger in various field operations. It's done by using IoT devices implanted in employees’ PPE and in the environment to process data collec ted on the system. Digital Control Tower can provide a smart dashboard that not only displays the KPIs but also helps the user prioritize his next steps. It may provide an overall view of the project's progress and KPIs, as well as get to the root of a problem in a specific installation area, raise red flags and alerts, and function as a user's assistant by predicting errors early on.

This paper is based on the analysis of miscible WAG for an onshore Middle-East field, with strongly undersaturated light oil. Water Alternate Gas operations have been ongoing for around 5 years, which is relatively recent compared to more than 40 years of production history. Goal of this work was to assess the efficiency of this miscible hydrocarbon WAG and to optimize it on the different compartments, with respect to miscibility, voidage replacement, and recycling. As this is a large mature field, with WAG operations dispatched on around 50 injectors and 9 fault blocks (compartments), the method of analysis had to be robust with respect to the different injection strategies followed in the past. It was essentially based on injection and production data, but also used pressure data when available. We computed the following dimensionless variables: oil recovery factor, BSW, voidage replacement ratio (VRR), and also WAG ratio and gas recycling ratio (GRR). Their evolution versus time was analyzed and compared between fault blocks. Using dimensionless variables allowed to compare fault blocks with different initial volumes in place, and to illustrate trends versus time. It was also found beneficial to lump some compartments, when communication was substantiated by pressure data. On the production side, we used the conventional BSW and GOR variables to quantify the water and gas recycling ratio. On the injection side, we observed that in some compartments, the historical WAG ratio was too low in the oil zone, which could be quantified by excluding the peripheral water injection volumes. The analysis allowed also to estimate the gas utilization factor and efficiency, which confirmed the overall high efficiency of miscible gas injection in 3-phase mode. It was also found that the injected fluid efficiency correlated with geology: gas injection tends to be more efficient in zones with high permeabilities at the bottom (coarsening downwards), while water injection is better adapted to zones with high permeabilities at the top (coarsening upwards). Estimating these water and gas efficiencies also allowed to optimize the injection strategy on a field level, by comparing the water efficiency with other units of the field only under waterflood.

Foam Enhanced Oil Recovery (EOR) has been employed as an improved recovery method due to its best sweep efficiency and best mobility control over the other injection method such as gas flooding, water flooding and other EOR methods. Foam which has high viscosity illustrates great potential for displacing liquid. The relative immobility of foam in porous media seems to be able to suppress the formation of fingers during oil displacement leading a more stable displacement. However, there are still various parameters that may influence the efficiency of foam assisted oil displacement such as oil properties, permeability of reservoir rock, physical and chemical properties of foam, and other parameters. Also, the interaction and displacement patterns of foam inside the porous media are remained unknown. Thus, in this study, we investigated the three-dimensional (3D) characteristics of oil recovery with gases, water, surfactant, and foam injection in a porous media set-up. By using CT scanning machine, the fluid displacement patterns were captured and analyzed. Moreover, the effect of oil viscosity on foam displacement patterns is studied. The study provides a qualitative and quantitative experimental visualization of 3D displacement structure, oil recovery with gases, liquid and foam injection. As a result, the comparison of fluid displacement patterns between gases, water, surfactant and foam injection show that foam has the good ability in sweeping and forms stable displacement front. The combination of surfactant, liquid and gas, which makes up foam resulted in a synergistic effect in oil displacement. On the other hand, viscous fingering, gravity segregation, trapped oil phenomena are shown in gas flooding and liquid flooding experiments. Thus, foam which displaced stably across the permeable bed resulted in the highest oil recovery factor. The mechanism of foam flow in porous media was understood in this study. Foam, as a series of bubble, burst and become free moving liquid and gas particles when in contact with oil and porous media. Therefore, two displacement fronts could be found from the foam injection experiment, in which the front layer moving ahead in contacting with oil bank is the discontinuous gas/liquid layer and followed by stably foam bank at the back. Due to the stable displacement of foam bank, the effect of oil viscosity on foam displacement is suppressed and showed no distinction in terms of displacement patterns. The flow regimes are found to be the same despite different viscosity of displaced oil. There has been no linear correlation proved between the oil viscosity and oil recovery factor.

The fourth industrial revolution (IR 4.0) has brought about many exciting and game changing technological advancements in recent years that span across different industries. Our petroleum industry was no exception. In this paper, we will present realizations of IR 4.0's fruitful impact on multiple upstream production engineering and operation problems. The first IR 4.0 technology uses machine learning techniques to predict scale inhibition and design inhibition programs that arrest scale formation. Scale formation is a common oilfield problem that consumes a lot of expense from operators. The machine learning method has shown its ability to curtail such expenses and manage risks associated with scale formation. The second technology is modeling the reliability of downhole Inflow Control Valves (ICVs) and predicting their failure. The technology is based on advanced big data analytics and uses automated statistical techniques to achieve the method objectives. This technology provides production engineers with an analytical decision-making model to predict ICVs failures and suggest the optimum frequency for stroking or cycling of the downhole valves as a preventive maintenance practice. The third IR 4.0 technology is the automated well integrity risk ranking. This particular technology uses smart interfaces and advanced computation algorithms applied on big data to assign (or weigh) risks of a well in terms of well integrity. This intelligent integrity ranking or classification shifts focus to wells prone to integrity failures more than the healthy ones. In addition, the method helps optimize integrity surveillance resources and prevents the obvious setbacks from a well integrity issue. The paper will explain detailed methodologies of all three IR 4.0 technologies and outline expected results from field implementation of those technologies.

Objective/Scope One of the main concerns of Oil & Gas Plants and associated Buildings is how to improve indoor air quality (IAQ) and tackling viruses. IAQ can be affected, or may become under high risk by some of nearby gases, microbial contaminates or energy stressor that affect the HSE condition. This paper presents the main factors that been considered to provide practical solutions to achieve high IAQ and tackling viruses (such as COVID-19). Methods, Procedures, Process IAQ refers to the air quality within and around the plants/buildings. IAQ can usually be affected, or may become under high risk by nearby gases, particulates, microbial contaminates or any mass that affect 100% HSE. Inadequate air quality in building will increase the risk and impact on transferring viruses to people (such as COVID and Flue) and equipment performance (such as equipment failure, components corrosion and short circuits on control board). Survey and data was recorded to evaluate air quality performance in atmosphere instead of assuming it. Accordingly, the impact of inadequate IAQ was studied and evaluated. Results, Observations & Conclusions The international standard set a good IAQ in respect of gas concentration and human who works inside buildings in a way that less than 50% people should not detect any odor, 25% should not experience discomfort, 10% should not suffer from mucosal irritation and 5% should not experience annoyance. Study concluded that inadequate IAQ inside the building will affect people performance/health and installed equipment performance. In addition, improper HVAC system operation will be become breeding site for odor causing mold and bacteria, specifically on cooling coil. Hence, several technics were studied to improve IAQ, by installing Ultraviolet (UV) light to stop growing bacterial inside the HVAC system, installing chemical filter in air intakes to remove atmospheric dust, gases and bacteria by 100%, upgrading filtration efficiency to MERV-13 or highest achievable to capture at least 75 – 95% of airborne particles between 0.3 and 1.0 micron, increase outdoor air ventilation and temperature/humidity control. The performance of HVAC system and quality of air inside building were monitored by simulating IAQ based on ISO 16890, filters life cycle, energy consumption, and the results were found 100% satisfactory and provided solutions that are now successfully implemented in all new and some of the existing buildings. Novel/Additive Information There are several buildings with similar issues and these approach/technics now being adopted in new constructed/existing buildings to protect human and asset integrity, which will support ADNOC Way by sustaining safe environment operation, lower health risk, reduce of equipment failure, reduce maintenance cost and 100% HSE. There are numbers of occupied buildings across the world were surrounded by aggressive gases/pollution with poor IAQ and above approaches it can be followed to realize larger benefits.

Operator Proactive Monitoring is one of the critical paths to Ensure Safe Production. The objective is to ensure that facilities are proactively monitored to retain the best possible level of situational awareness. It is achieved by monitoring and control the unit and equipment to avoid exceeding a safe limit while meeting all operational and business targets. It promotes early detection & appropriate intervention to an arising abnormal situation. Operator Proactive Monitoring covers a wide range of activities from a control room and field operation. ADNOC Gas Processing, in line with the digital transformation program, has enterprise assets/equipment through implementing Operator Proactive Monitoring for control room and field operator. Operator rounds play an essential role in improving plant reliability and safety. This research aims to measure the effectiveness of the Operator Proactive Monitoring by the Ruwais NGL Operation division at ADNOC Gas Processing. By "doing the right thing," Operator Proactive Monitoring effectively supports and improves process safety culture in the operation business of Ruwais Plant division of ADNOC Gas Processing.

This paper discusses how the application of large, gas turbine-based power blocks (>50,000-hp) in pipeline compression stations can contribute to lower capital costs, improved lifecycle performance, and reduced carbon emissions. For illustrative purposes, two compression facility power block configurations (nine 30,0000-hp trains vs. five 55,000-hp trains) are compared on the basis of capital expenditures (CapEx), operating expenditures (OpEx), availability, efficiency, and operating flexibility. A summary of the study's results are as follows: – Net present value (NPV) analyses show that 5x55,000-hp ISO trains can result in up to $50 million reduction in CAPEX vs 9x30,000-hp ISO trains – By having fewer trains, operations & maintenance (O&M) costs can be reduced by as much as 20% – Lifetime fuel savings with a 5x55,000-hp train configuration vs. 9x30,000-hp trains are estimated at $40 million, owing to the increased operating flexibility of modern gas turbines, even at partial loads. The paper will also present considerations for digitalization, modular construction, and package integration – with a particular focus on how these measures can be leveraged to lower execution risk and enhance the lifecycle performance of gas turbine-driven compression trains.

This paper describes the utilization of a riserless light well intervention (RLWI) vessel with well control system and flexible downlines to execute a re-stimulation campaign on subsea injection wells located in the Norwegian Continental shelf in the summer of 2019 and 2020. A riserless light well intervention (RLWI) vessel with well control system and flexible downlines was used in combination with a stimulation vessel. The objective of each campaign was to increase injectivity in the wells with high-rate acid treatments. The lessons learned from the 2019 campaign were applied to the 2020 campaign, resulting in reduced health and safety exposure, and improved operational efficiency. Analysis of the treatments and their impact on injection and field pressure support was conducted to assess the effects of these improvements and provide insights for how the treatments can be applied to vessel stimulation in general. In each campaign, the RLWI vessel was connected to the subsea asset, and a dedicated stimulation vessel provided stimulation fluids via a high-pressure flexible hose connected between the two vessels. Both campaigns saw high treatment pump rates of up to 60 bbl/min with low-pH crosslinked gel fluids, 28% hydrochloric acid, and diverters in the form of ball sealers and rock salt. Hose deployment methodologies between the two vessels differed in the two campaigns. The 2019 campaign employed a conventional transfer utilizing the marine crane on the RLWI vessel to lift and lower the hose into a preexisting hanger. Learnings from this operation led to the development and use of a winch pull-in method in which the hose connection was accomplished with a hot stab connector on the RLWI vessel, eliminating human intervention and the use of the crane. The 2019 and 2020 campaigns successfully stimulated five and six subsea injection wells, respectively, and realized post-stimulation improvement in injection rates of 135%. One year of field monitoring from the first campaign shows pressure support benefits with improvements in production throughout the connecting area of the field. The winch pull-in method of hose deployment between the vessels achieved time improvements of 8 hours per stimulation treatment. In addition, the added flexibility of not needing to be within crane reach gave the operation extended working weather limits. The overall result was a significant improvement in operating efficiency between the 2019 and 2020 campaigns. The operations showed how high-rate stimulation can be achieved on subsea assets with the use of an RLWI and stimulation vessels. Detailed analysis of the operational efficiency of each campaign was performed, and the improvements from one campaign to the next documented. The winch pull-in method is a new way of high-pressure hose transfer that can be applied to future stimulation vessel operations to improve operational safety and efficiency.

Following the increase in demand for natural gas production in the United Arab Emirates (UAE), unconventional hydraulic fracturing in the country has grown exponentially and with it the demand for new technology and efficiency to fast-track the process from fracturing to production. Diyab field has historically been a challenging field for fracturing given the high-pressure/high-temperature (HP/HT) conditions, presence of H 2 S, and the strike-slip to thrust faulting conditions. Meanwhile, operational efficiency is necessary for economic development of this shale gas reservoir. Hence "zipper fracturing" was introduced in UAE with modern technologies to enable both operational efficiency and reservoir stimulation performance. The introduction of zipper fracturing in UAE is considered a game changer as it shifted the focus from single-well fracturing to multiple well pads that allow for fracturing to take place in one well while the adjacent well is undergoing a pumpdown plug-and-perf operation using wireline. The overall setup of the zipper surface manifold allowed for faster transitions between the two wells; hence, it also rendered using large storage tanks a viable option since the turnover between stages would be short. Thus, two large modular tanks were installed and utilised to allow 160,000 bbl of water storage on site. Similarly, the use of high-viscosity friction reducer (HVFR) has directly replaced the common friction reducer additive or guar-based gel for shale gas operation. HVFR provides higher viscosity to carry larger proppant concentrations without the reservoir damage, and the flexibility and simplicity of optimizing fluid viscosity on-the-fly to ensure adequate fracture width and balance near-wellbore fracture complexity. Fully utilizing dissolvable fracture plugs was also applied to mitigate the risk of casing deformation and the subsequent difficulty of milling plugs after the fracturing treatment. Furthermore, fracture and completion design based on geologic modelling helped reduce risk of interaction between the hydraulic fractures and geologic abnormalities. With the application of advanced logistical planning, personnel proficiency, the zipper operation field process, clustered fracture placement, and the pump-down plug-and-perforation operation, the speed of fracturing reached a maximum of 4.5 stages per day, completing 67 stages in total between two wells placing nearly 27 million lbm of proppant across Hanifa formation. The maximum proppant per stage achieved was 606,000 lbm. The novelty of this project lies in the first-time application of zipper fracturing, as well as the first application of dry HVFR fracturing fluid and dissolvable fracturing plugs in UAE. These introductions helped in improving the overall efficiency of hydraulic fracturing in one of UAE's most challenging unconventional basins in the country, which is quickly demanding quicker well turnovers from fracturing to production.

The evolution of the energy market requires companies to increase their operating efficiency, leveraging on collaborative environment and existing assets, including Data. A new focus on data governance and integration is needed to maximize the value of data and ensure "real-time" efficient response. The decoupling of data from applications enables organization by domain and data type in one cross-functional data hub. This scheme is independent from the scope of the activity and will therefore maintain its validity when dealing with new business requiring subsurface data utilization. The integrated data platform will feed advanced digital tools capable to control the risks, optimize performance and reduce emissions associated with the operations. Eni is putting this idea into practice with a new data infrastructure which is integrated across all the subsurface disciplines (G&G, Exploration, Upstream Laboratories, Reservoir and Well Operations departments). In this paper, the example of real time data exploitation will be discussed. Real time data workflow was first established in well operations for operational supervision and later developed for real time performance optimization, through the introduction of predictive analytics. Its latest evolution in the broader subsurface domain encompasses the application of AI to operations geology processes and the extension to all operated activities. This approach will equally support new company goals, such as decarbonization, increasing performance of subsurface activities related to underground storage of CO2 in depleted reservoirs.

Many oil & gas companies embarked on their Digital Transformation (DX) journeys with rapid adoption of emerging digital technologies. Successful digital transformation initiatives are necessary for Oil/Gas Companies to improve efficiencies, streamline their operations and meet pressing challenges for cost reduction, increased efficiency, and improved safety. Oil & Gas fields and processing facilities require robust and reliable telecommunication infrastructure to support the application of much needed digital technologies. The availability of high-speed connectivity has been a challenge for many Oil/Gas companies operating in remote or hazardous locations. The latest Fifth Generation cellular technology (5 G) addresses such essential Oil/Gas requirements as increased speeds/bandwidths, very low network latencies, ultra-reliable communications, and the capacity to handle large number of users. 5G is designed around following technologies: Small (micro) cells requiring less power, Higher frequencies offering bigger data handling capacities, Cloud and Edge Computing for low network latencies and added security. These 5G design features will enable numerous Oil/Gas applications such as Industrial Robots/Drones, Virtual/Augmented Reality, Video Surveillance with Artificial Intelligence (AI) features (Face Recognition, Object Recognition & intelligent Image processing), Remote Asset Management, Industrial IoT communication between Sensors, Gateways and Device Controllers, Pipeline Leak Detection Systems, Telemetry and SCADA. 5G is therefore poised to be a key enabler in Digital Transformation. The UAE has an advanced telecom infrastructure that offers customers high speed fibre optic connectivity. UAE telecom operators have also been quick to deploy 5G in main cities. Etisalat for example is running a 5G pilot on Das Island with ADNOC Offshore and a major Network Supplier to test potential use cases of the technology in the O&G industry. The push for 5G in O&G will benefit from cooperation between the O&G industry, the telecom operators and technology providers. The role of Governments and the Telecom Regulators can further accelerate adoption through allocation of frequency spectrum to enable 5G Private Network model of deployment. The private network model is crucial for the Oil & Gas industry in view of the special requirements, nature and remoteness of oil and gas installations.

Distributed Fiber-optic Sensing (DFOS) provides real-time data acquisition, monitoring and diagnostics for well stimulation and well spacing assessment. These include measurements of Distributed Acoustic Sensing (DAS) with high frequency acoustics in treatment wells, and low frequency strain/temperature sensing in offset monitor ones. The goal of this integrated study is to show the value of multi-well fiber sensing for real time fracturing diagnostics and stimulation optimization. By integrating near field injection to far field strain responses we assess overall reservoir development. The availability of fibers on both the treatment well and a nearby observation well allows us to investigate the near-wellbore injection profile and the far-field strain fracture propagation. Quantitative strain levels clearly respond to the effects of well distance, location and treatment well stimulation design. Monitoring well strain measurements of fracture density and triggered stimulated span were logged and compared to acoustic signals in the nearfield stage by stage. DAS interpretation was conducted during the treatment of each stage indicating the effectiveness and efficiency of the completion design. Results show that this is a very effective tool to better understand the performance of the fracturing treatment by digital transformation using DAS data. In addition, acoustic and strain measurements also validated its diagnostic capability for real-time operation monitoring. In this presentation we show how the near-field acoustic and far-field strain measurements allow for better understanding of the completion efficiency. This is by assessing the far field response to quantified DAS injected signals in the treatment. This analysis takes advantage of fiber installation on both the treatment and nearby monitor well. The fluid and proppant allocations in the near field were performed on the treatment well using relative acoustic intensities. Meanwhile, the fracture propagation induced strain change is recorded by the offset fiber well. Using this fiber data reveals dominant clusters and stage bias from near-field injection profile. Simultaneously the far-field identified fracture counts from strain further enable a geomechanical assessment of the stimulated reservoir and assess the effectiveness of the completion design. Multiple DAS fiber equipped wells not only provide single diagnostic tool for each of the fiber well, but also demonstrate significant integrated assessment of the stimulation effectiveness, completion efficiency, well interaction, and reservoir description. Availability of near and far field measurements constitutes an important tool to assess properties of the reservoir. Here we show how different vantage points can help illuminate a fracturing program in unconventional reservoirs.

A large GCC National Drilling Contractor is planning to trial a new MSE (Mechanical Specific Energy) Drilling advisory system based in artificial intelligence (AI) on a conventional drilling rig. This system works by means of calculating the optimal auto driller input parameters to achieve higher drilling efficiency. The objective of the MSE based Drilling Optimization system is to drive drilling efficiency by way of advising surface drilling parameters (WOB and RPM). The system will be tuned to advise/automatically modify WOB and RPM for each specific run, section, or well. The parameters can be adjusted in one of the two following ways: Advisory Mode: A recommended WOB and RPM value is sent to the driller, who then manually applies the setpoint change Control Mode: The setpoints are sent to the automatic driller for instant and automated application The system shall enable reduction of NPT and rig days to drill wells by increasing efficiency with consequent cost reduction efficiency by utilizing advanced elements of Artificial Intelligence (AI).

Meeting the production demand in today's market without sacrificing performance of the artificial lift method is critical. Aggressive flowback procedures lead to solids production and unplanned electric submersible pump (ESP) shutdowns because of solids overload. A novel pump protection system has been designed, tested, and installed in the field. The system enhances the ESP life, improves restarts, and reduces downhole vibrations and unplanned shutdown by controlling the solids flowback and sending solids-buildup pressure signals. A comparative study on three ESP wells in the Delaware basin (US) demonstrated the efficacy of the system. The system comprises of an intake sand control screen and valve assembly. The novel stainless steel wool screen acts as a three dimensional (3D) filter capable of filtering out particles of 15 to 600 μm, and the valve assembly activated by differential pressure across the screen creates a secondary flow path to allow cyclic cleanup of the screen. Stainless steel wool screen with variable pore sizes is used as the sand control media for its high efficiency in preventing the flow of most of the solid particles. When the solids build up on the screen surface, the valve assembly opens upon reaching a preset differential pressure to enable flow past the screens and into the ESP and allows sands deposited on the screen surface to fall off. The pump protection assembly was tested at surface and installed in three wells along with downhole ESP gauges measuring pressure, temperature and vibrations after pulling out existing ESP completions. Qualification testing confirmed the opening of the valve assembly after solids buildup on the stainless steel wool screen. It also validated that the deposited sand fell-off from the screen surface after flow diverted through the valve assembly and pressure differential across screen dropped. In the field installations, the run life of the ESPs improved by an average of 35%, with comparable production volumes and slow drawdowns. In addition, the number of ESP shutdowns related to sand and solids was reduced by as much as 75%, improving longevity of electrical components. The success rate of ESP startups after planned and unplanned shutdowns also improved by 22%. The increase in inlet pressure captured via the downhole gauges when the valve assembly opened indicated the sand control prevention and mitigation system was bridged, and ESP replacement should be scheduled to minimize deferred production from a solids-induced ESP failure and to minimize surface solids management costs. The vibration signal data obtained from downhole sensors confirmed the reliability of the system. Overall, results demonstrate that the system designed is successful at increasing ESP run life without detriment to well production performance. The new, field-proven pump protection system along with its components and the completion design substantially increase life of ESP by reducing the number of shutdowns related to sand overload, reducing shutdowns, reducing overall vibrations, increasing the probability of successful start after shut-in, and increasing the performance reliability during fracturing of a neighboring well. Consequently, more wells that are looking to increase the ESP life can now benefit from this technology and increase output.

Oil prices see large fluctuations peculiarly over the last eight years due to natural disasters, political instability, and Covid-19 pandemic shock. These prompt to anxiety towards expenditure in planning and forecasting of a field development plan (FDP). Economic optimization of a reservoir under water drive can be extremely tedious and time consuming especially for complex field. Traditionally, upon completion of forecast optimization on fluid production, reservoir engineer willhand over the reservoir models to petroleum economist for economical evaluation. If the chosen development strategy is not economically viable, the model strategies will have to be updated, and continue the repetition of financial evaluation all over again. Hence, this paper established an automated workflow that diminished the dilemma on iterations obligation between simulation runs and financial reviews in searching for most efficient waterflooding strategy. The automated workflow is accomplished by bridging three tools together seamlessly utilizing python scripting. These include the cash flow economic spreadsheet model, the dynamic simulator, and an assisted uncertainty analysis tool. The process first started with defining the economic parameters such as OPEX, CAPEX, oil price, taxes, discounted rates, and other financial parameters on an annual basis in spreadsheet. The uncertainty parameters: water injection rate, maximum water cut, and injection duration will be evaluated during forecast optimization to produce project efficiency indexes: Net Present Value (NPV) and Benefit-Cost Ratio (BCR). This integration was achieved by python script that automatically creates a coding path which exchanges simulation production and economic spreadsheet data at every simulation time step and each development strategy, that require no manual intervention. The integrated economic-dynamic model workflow has successfully applied on West Malaysian field and Olympus model, a development strategy that maximize oil recovery without neglecting cost of water disposal, storage for total water produced from the reservoir. This paper successfully identified the most efficient waterflooding strategy and production constraints for each well using BCR as objective function for optimization. The optimum development scenario does have a BCR which is more than 2 which show that investment on that particular development strategy is profitable. The results also demonstrated a crucial impression that the highest oil cumulative production may not results in high BCR due to cost involvement in resolving water production and field maintenance services. This paper outlined the methodology, python scripting codes, and how integration automation works that successfully optimized an injection strategy in a development project using economic model from third-party application. The results of this automated workflow demonstrate a successful utilization of new technologies and simple customize programming knowledge that promote cross-discipline integration for enhanced work-time efficiencies in problem solving that is suitable for all reservoir model type to determine its success rate and economic viability during FDP.

Seawater is an essential fluid used in various process circuits, such as cooling, reinjection into the wells and utilities, etc., in the offshore oil and gas industry. Vertical pumps facilitates with lifting seawater to the platform. This study investigates and compares two pump alternatives that has been widely used in oil and gas industry for seawater lift application: Vertical line-shaft pump and Electrical submersible pump. Existing seawater lift pump operating parameters are used as the basis of this study. The pump that is considered for the study has a flow rate of 3415 US GPM (776 m3/hr.) with a total head of 250 ft. The motor rating is 350 HP. The overall length of the pump is 21 meters. The main methodology used is a Life Cycle Cost Analysis (LCC) where the total cost of ownership of the vertical line-shaft pump and electrical submersible pump were analyzed for a period of 30 years. Furthermore, this research also addresses the operational drawbacks associated with both the pumps. Submersible pumps have higher initial capital investment cost when compared to line-shaft pump of similar capacity and size. The energy consumption cost of submersible pumps are higher mainly owing to lower efficiencies of the motors. The power factor for submersible pumps are lower in relation to line- shaft pumps. One of the main benefits of submersible pumps are their less installation and pump pullout time. Submersible pumps occupies lower space above ground when compared to line-shaft pumps. Additionally, submersible pumps are less noisy and have lower vibration in comparison to line-shaft pumps. This paper aims to provide key information and knowledge for engineers to make prudent decision regarding selection of the most cost effective pump for the seawater lift application with a tangible added cost value to both Capital Expenditures (CAPEX) and Operational Expenditure (OPEX).