With the advent of IIoT enabled Edge Analytics, and its ability to run Machine Learning based inference at the extremities of a production network, it has become essential to enable Operators and Subject Matter Experts to transfer their knowledge to Edge Computing Devices. This paper discusses the application of Edge Analytics enabled Augmented Intelligence for wells operated by Electric Submersible Pumps, where Machine Learning and Pattern Recognition Models help detect anomalous events in multivariate time-series data. These Models runs on Edge Computing Devices where identify newly discovered and well known ESP performance patterns that can be labelled by a Subject Matter Expert. Once these patterns are identified and tagged, the Models are retrained and pushed back to the Edge Computing Device, where they continue to detect and predict patterns in real-time.

The Mangala oil field in Barmer, Rajasthan is one of the largest onshore fields in India. The field is under an active polymer flood with over 300 wells injecting >400 kbwpd. Jet pumps have been the main mode of artificial lift for the field since production commenced in 2009. The jet pumps are "reverse circulation" type with the power fluid (water), pumped down the annulus. Despite their low efficiency, jet pumps are ideal for Mangala because heated water is used for the circulation fluid which avoids wax deposition in well tubulars. Simple performance curves, often used in commercial packages, work well under two phase liquid only or low GOR conditions. With high gas volume fractions and higher drawdowns, the additional complexity of critical flow is introduced; this occurs when the fluid velocity reaches the speed of sound within the jet pump. These conditions are often encountered in the Mangala pumps, and many jet pump solutions become grossly inaccurate when used for these conditions. A field-wide network model is being used for production optimization; the model employs coupled power fluid and production network systems. Given the size of the power fluid network, an accurate and fast method for jet pump performance under three phase conditions is a prerequisite to the modelling of both well behavior and jet pump sizing. This paper presents a full solution of the fundamental jet pump equations, which are based on Bernoulli’s principle and the conservation of momentum. The method follows the classic solution presented by Cunningham ( 1970 , 1995 ), which made simplifying assumptions of perfectly incompressible liquids and ideal gases. The proposed technique eliminates these simplifications, making the solution applicable for the situations commonly encountered in the Mangala field. Existing jet pump models for Mangala are based on spreadsheet solutions. These solutions are slow and are practical only for the sizing of individual jet pumps. The new model presented in this paper solves the fundamental equations using numerical techniques and properly accounts for high compressibility fluids, multiphase flow and critical flow. The model was written in Python, which is an object-oriented language well suited to modeling the individual components of the system. The model solves the integrals involved in the revised Cunningham equations, using Newton-Raphson techniques to solve the equations iteratively. The model is used to generate complete (and complex) VLP curves in standard formats which can then be used directly with network models. The new model executes 25-100 times faster than the previous spreadsheet model.

ADNOC Offshore started-up full field gas-lift activation for the first time in 2020. This major step will unlock field's potential by increasing reservoir withdrawal and increasing wells life by mitigating water production / breakthrough. This paper details the successful application of gas-lift from design during appraisal phase and early production stage to full field implementation. Fit for purpose design was implemented through multi-disciplinary studies and work. A strong change management in operating philosophy was requested to take onboard all stakeholders: Field development, Field Operation, Wells operation, Drilling and completion. Following appraisal and early production phases on a green field, wells design was optimized to ensure proper activation in most of the producers (two over three reservoirs developed). Due to full field development phasing, the first 30% of the wells completion were designed based on early production phase data. Before full field commissioning started, in well gas-lift valves were designed and installed, integrating all the dynamic information gathered during natural flow production. Valves change out was performed with the highest HSE standards, and taking into account full field development timing in order to reduce downtime and therefor maximize production. As gas-lift is new in the operating company, a strong change management was required: operating with gas-lift by field operation team, Completion design, Drilling and Gas-lift Production with SIMOPS. Gas Lift implementation will ensure the future oil production of the field as water injection and production will increase. Gas-lift practice implementation led to modifying the operating company's rules in multiple and deep aspects: – Improve field team competencies in handling high pressure gas-lift system, – Increase completion and wells operation complexity, – Implement new SIMOPS rules. As a first achievement, one well under reservoir integrity issue (low productivity due to reservoir collapse) was re-activated and production of existing wells was increased of several thousands baril. Further increase in production is expected in the following months as implementation is deployed to all required wells.

This paper describes a data-centric approach for increasing asset reliability and performance through the creation of single-source-of-truth environment (i.e., an Evergreen Digital Twin). For many oil and gas facilities today, asset data is spread across a multitude of applications and databases, and most are not connected. This paper will show how data can be aggregated and contextualized, and combined with powerful simulation, analytics, and asset performance management (APM) tools to enhance performance, reliability, and maintenance. For illustrative purposes, an oilfield use case will be presented involving the implementation of a an open and flexible operational intelligence platform (OIP) and an advanced simulation platform. In the proposed scenario, the OIP makes it possible to integrate and contextualize data from the simulator – making it accessible and useful for field operations personnel. The paper outlines the benefits and capabilities the combination of these tools can enable – including visualization and optimization of well production and the ability to simulate "what if" scenarios. It also discusses how artificial intelligence (AI) and/or APM tools could be integrated within the digital asset portal to provide early prediction of equipment failures and conduct failure mode analyses. The solution has been conceptually and technically proven; however, it has not yet been implemented by the field operator. Overall, the use case highlights the value that can be realized by integrating data from disparate sources within a one-stop environment to make better operational decisions regarding complex oil and gas assets and facilities.

Abstract In reservoirs management, sometimes it becomes difficult to identify which injector is supporting which producer(s) by graphs visual inspection. Available built-in correlations like Pearson –within common spreadsheets-, only valid for strictly monotonic (only increasing or decreasing) trends. A situation that is nearly impossible to see in real production/ injection trends. To resolve this issue, we developed a correlative tool in spreadsheet based on Spearman's correlation to assess communication degree between wells using production/ injection data. The method essentially implemented then non-parametric Spearman's correlation - valid with non-monotonic trends- and used visual basic application (VBA) coding language to provide easy to use worksheet. The input data needed are: production/injection data of the well(s), with any desired parameter like oil rate, water rate, GOR or water cut. After running the code, the outputs are numbers between −1 and 1 reflecting correlation coefficients between WI-OPs production parameters or OP-OP parameters. Zero or close to zero means no correlation, number close to 1 mean very strong proportional correlation and a number close to −1 reflects inversely proportional correlation. The tool was built successfully and enabled quick injection/production correlation between one injector and several producers at once using available production data. Also, it can run production/injection correlations between one producer and several injectors. Currently, it can measures correlation between one injector with up to 32 producers, or with 32 different parameters of several producers like water cut, gas oil ratio (GOR), oil rate, water injection rate, and water production rate. Moreover, it can correlate between producer-producer to check for interference. The code was found to be fast. Results from this tool were compared to results obtained from streamlines models and tracer injection in two different fields, one was naturally fractured carbonate and the other was sandstone. Evaluation of the tool ability to find true interactions between wells was achieved by comparing results of correlations coefficient with underground flowing tracers and streamline simulations. Some agreement was found between, streamline models, tracer surveys and Spearman correlation in well known areas to have well-well communication. Some limitiations were identified. Nevertheless, the tool can be used as a quick scanning tool for communication between wells. This tool provides an addition to the inventory of existing investigative methods like tracers, streamlines, and diagnostic plots and gives more weight to results from these techniques on identifying which wells in communication. The tool is easy to build, simple to use and fast to run. The tool might help reservoir management teams to better manage reservoirs, and free more time for engineers to improve production and increase oil gain.

Abstract The objective of the paper is to share knowledge on an innovative design of the conventional dummy gas lift valves (GLV) which allows the deployment of water tracers within a polymer matrix ( Figure-1 ). These tracers are released in contact with water and are detectable at surface as soon as water breaks through in the well. This technology does not compete with the established and more expensive conventional tracer deployment downhole, in segmented horizontal wells, for instance, whereby the reservoir zones producing water are detectable. Here, the deployment is in the upper completion of any well equipped with gas lift mandrels, whereby a new design of a dummy valve allows the inclusion of water tracers which are released in contact with water. At surface, in the first stage separator, or manifold, which receives fluids from many wells, a specific well producing water can be detected ( Figure-2 ). Like any dummy GLV, this new tool containing tracers can also be deployed using a normal slick line and does not prevent any cased hole logging operation, like other downhole tracer deployment systems in the market.

Abstract The giant heterogeneous carbonate field presented here consists of multi-stacked reservoirs and is located in the Arabian Gulf approximately 135 km north-west of Abu Dhabi. The reservoir named "T" measures 9 km by 11.5 km, with large accumulation of 35 °API oil with initial gas oil ratio of about 400 scf/STB. The current reservoir pressure is around 2,700 psi; many of wells are unable to flow naturally against the high sealine pressure, due to low productivity and relatively low GOR. To produce these wells, "artificial lift" or lower sealine pressure are required. A collaborative team of Reservoir Engineers, Petroleum Engineers and Geoscientists was assigned to find a sustainable and cost-effective solution to produce reservoir "T" in order to evaluate its potential. The team conducted a detailed and comprehensive study of the field starting from reservoir "T" and then expanded to the other reservoirs. As a result, the proposal of an "Auto Gas Lift" (AGL) pilot was formulated to use gas from the reservoir "C" (underlying reservoir T) to artificially lift the oil produced from reservoir T. AGL is a cost-effective artificial lift system, directly replacing for conventional gas-lift equipment, gas compression facilities, gas transport pipelines and ancillary equipment. This technique has been identified as the most suitable for such mature offshore field, where existing platforms have limited spare load and space capacity and could not accommodate gas-lift compression facilities or ESP topside equipment. The first pilot completion has been designed. It consists of a perforated downhole high GOR zone from which gas is bled into the tubing at a rate controlled by a downhole gas lift valve. The gas produced from high GOR reservoir C will allow reservoir T to flow by reducing the hydrostatic head of the fluid column in the well. Artificial lift has not been implemented yet in the field. However, several artificial lift techniques, such as Electrical Submersible Pumps or conventional gas lift, are foreseen in long term development plans. "AGL" technique, if successful, could represent a cost-effective solution for further appraisal of this reservoir, without waiting for the implementation of large-scale artificial lift techniques.

Abstract This paper presents a process flow of an efficient method to diagnose, identify and optimize non-optimum gas lifted wells for a gas-lifted oil field. During normal day-to-day operations, a Petroleum Engineer's deliverables include well lifting performance analysis as well as optimization. Gas lifted wells are deemed optimized when the injection point is at the deepest mandrel possible and no multi-pointing scenario is occurring. However, the real-life well production can be unstable, corroborated by real-time data of flowing tubing-head pressure, casing head pressure and gas lift injection rate. The analysis of these real-time data can infer non-optimized lifting, where one of the symptoms is valve chatter. This in turn translates to well slugging and affects the whole production system. In a field with a large number of gas lifted wells, the diagnosis of these types of cases requires a substantial investment of time each month. By utilizing this workflow, the time spent for lifting diagnostics can be reduced, as well as contributing to time savings for other meaningful tasks, i.e. designing new gas lift system on non-optimized wells. The Gas Lift Diagnostic workflow, which is developed using pre-defined logic and the existing well model, eliminates the time-consuming manual task that slows down work and streamlines the processes to generate more value for the business and organization.

Abstract Electrical Submersible Pumps (ESP) are an essential artificial lift method in oil fields when the reservoir pressure is insufficient to drive the well fluid to the surface naturally. One of Mubadala Petroleum's operated fields in particular experienced several ESP failures from downhole ground faults, which resulted in a run life much shorter than the typical average run life experienced in similar applications. As such, power supply quality is investigated to understand whether it could accelerate ESP system breakdown. Commonly, a Variable Frequency Drive (VFD) is employed to optimize operations as the reservoir conditions change. However, VFDs tend to generate transient and harmonic distortions as a result of electronic switching. Measurement tools, such as a power quality analyzer and an oscilloscope, are connected to VFD output to measure its power quality. Partial Discharge (PD) is considered to be a possible factor contributing to electrical failures. As such, a PD tool is connected to the medium voltage supplied to ESP to determine if any PD exists. The investigation of power supply quality focuses on the percentage of Total Harmonic Distortion (%THD) at three different locations in the system; input and output of VFD, and output of the step-up transformer. Since there are no international standards in place to regulate the power quality output from the drive, different VFD models create different levels of output harmonics. Our results show that two different models can give different levels of %THD, both in terms of voltage and current. However, acceptable levels are observed for all of the designs tested, ranging from 2-15%. Power transient and voltage spikes were also measured during well startup and shutdown period, and indicated no significant differences between VFD models, and no issues of concern. However, significant levels of partial discharge, as measured in nano-coulombs, are observed at the medium voltage measuring point through to the downhole cable connections. It indicated the possibility of electrical anomalies, which can result in cable insulation failure. The level of partial discharge on each specific connector piece can be performed further during the Dismantle, Inspection, and Failure Analysis (DIFA) process after the equipment is pulled out of the well. The primary impact of high harmonic voltage distortion in ESP power systems is excessive heating, which can accelerate insulation resistance deterioration. Partial discharge can also contribute to insulation failure of downhole connectors and cable splicing points. This paper provides a systematic approach to investigate the power quality system supplied to downhole ESP equipment, and the application of a partial discharge measurement method, which is new to the ESP industry.

Abstract Field presented here is located in the southern part of the Arabian Gulf approximately 135 km north-west of Abu Dhabi city. This giant heterogeneous carbonate field consists of multi-stacked reservoirs. The presented reservoir is highly fractured, it measures 9 km by 11.5 km. The reservoir has an original oil in place estimated at 2,240 MMstb of 35°API oil with saturation gas of 400 SCF/bbl. The reservoir pressure is +/− 2,700 psi and the sealine pressure in the field is +/− 1100 psi. The wells completed in T reservoir are unable to flow naturally against the high sealine pressure. Some wells are producing against by-pass line at 600 psi. Crestal gas injection was introduced to maintain the reservoir pressure. To produce the reservoir at its potential, it is required to use some artificial lift techniques. ESP was finalized to install for overcoming the high sea line pressure. As mentioned earlier the T reservoir is naturally fractured and has crestal gas injection, which lead towards 3,500 – 4,000 SCF/bbl and beyond the ESP limit. This requires some solution to handle the gas. A collaborative team of engineers was assigned to design and meet the challenge of such a premier application. The team conducted a detailed and comprehensive analysis of the T reservoir's fracture and fault characterization: the aim was to deliver an optimal well design meeting the requirement of ESP gas handling with minimum cost. A unique, fit-for-purpose dual completion (4-1/2" × 2-3/8") was finalized. The rigless ESP will be run through 4-1/2" tubing and 2-3/8" tubing will be utilized for gas handling and re-injecting gas in the sealine at surface. The dual completion will allow to handle high GOR through short string, which will lead towards the long ESP runlife. Before commencing the full development plan for T reservoir, this will be a pilot for better understanding the reservoir and its behavior. Rigless ESP was selected due to the advantages compared with conventional ESP: POOH and RIH of retrievable ESP parts through a conventional slickline unit Pumps can be replaced during the well life without rig workover. Low OPEX cost.

Abstract Gerotors are positive displacement pumps and potential artificial lift options in the oil and gas industry. This study presents the performance characteristics from physical testing of a unique one-stage, equal-walled gerotor pump design operating in oil and oil-air mixtures. The pump was tested at various rotational speeds in a flow loop. The performance results were obtained to ascertain potential design optimizations of the pump before embarking on manufacturing and testing of the field prototype pump. A physical prototype of a one-stage 400 series gerotor pump, suitable for application in a 5.5-inch casing, was designed, manufactured, assembled, and tested. Mineral oil and air were used as the operating media. For given pump outlet valve settings, the pump rotational speeds were set to 200, 250, 300, and 350 revolutions per minute (RPM). Gas volume fractions (GVF) at the pump inlet were varied from 0% to the maximum the current pump design could handle. For each test point, the corresponding pump parameters were measured. Dimensionless performance plots were established for obtaining pump performance at other flow conditions. The results showed that pump flow rate decreased with increasing differential pressure, typical of positive displacement pumps. At 200 and 350 RPM, maximum pump delivery is about 190 and 330 barrels per day (BPD) of oil, respectively, at zero differential pressure. The pump can supply flow against a differential pressure of up to about 5.5 psi at 200 RPM and 15 psi at 350 RPM. For the 200-350 RPM speed range, volumetric efficiencies varied from 30% to 73%, whereas the electric power input varied from 145 W to 191 W. When pumping oil-air mixtures, the current gerotor pump design can handle 15% GVF maximum, at 250, 300, and 350 RPM. For certain pump outlet pressures, the total fluid flow rates decreased as the GVF increased to 15%. The volumetric efficiencies at 15% GVF varied from 32% to 53%, for the 300 to 350 RPM speed range, whereas the motor electric power input decreased with increasing GVF up to 15%. In conclusion, increasing the pump rotational speed improves the volumetric efficiency and gas-handling capability of the gerotor pump. These observations will aid in the required design optimization to enhance the performance of the future field prototype gerotor pump. This study presents the capabilities of gerotors as potential artificial lift alternatives to handle liquid and gas-liquid mixtures for boosting applications in oilfield operations. The technology with additional design optimization can be readily integrated into oilfield equipment architecture. The mechanical simplicity of gerotors and their compactness provides a promising artificial lift substitute that may be implemented for downhole or surface production of liquid or gas-liquid mixtures in the oil and gas industry.

Abstract In a Japanese oil field, which applying jet pump (coiled tubing running, standard flow type, produced oil as power fluid containing asphaltenes and waxes) since 2014, unstable power fluid injection pressure has been observed since 2016 due to asphaltene deposition on jet pump nozzle area, which limited power fluid rate and therefore production rate. The objective of this study was to achieve high oil production rate by overcoming the pressure fluctuation due to asphaltene deposition problems. Asphaltene inhibitors (AI) from various suppliers were tested to measure asphaltene deposition amount as a laboratory screening. The best AI candidate was implemented in a field trial test during which, asphaltene deposition amount in strainers were measured, production oil was collected to measure asphaltene deposition rate under stock tank condition, and operation data was monitored and analyzed. To confirm the new AI efficiency, these data were compared with the ones during the original AI before starting the field test. This paper presents specific features which were found in the field test. Selected AI was efficient at dispersing asphaltenes. It achieved stable injection pressure and reduced asphaltene deposition amount in production oil sample. However, it became worse again within one month. The main reason was that the new AI worked as dispersant to delay asphaltene deposition so that asphaltenes finally accumulated under jet pump production system which is semi-closed loop. Asphaltene deposition amount on strainers increased during winter, especially shut down periods, because process temperature was close to ambient condition. This temperature-dependent observation means asphaltene deposition was highly influenced by wax deposition. A follow-up laboratory test revealed the asphaltene deposition amount decreased by adding paraffin inhibitor (PI). This field test result revealed the asphaltene and paraffin interaction in field scale.

Abstract Liquid loading is one of the biggest challenges in operating gas condensate wells of a depletion reservoir. Analyzing this bottleneck using physics-based model estimations is one of the key methodologies in an integrated digital production system, which can help users to take preventive actions, thereby saving cost, time, and efforts considerably. This paper demonstrates the identification of the liquid loading condition in existing producing gas condensate wells using the analytical tools and automated workflows in an integrated framework. The analytical workflow to investigate liquid loading bottlenecking requires calibrated and representative well models as a first step. These representative well models incorporate a tuned compositional PVT model as a fluid parameter model, and such model outputs match with wells deliverability and historical production trends. Subsequently, the calibrated models are then integrated into a digital platform consisting of automated well analysis workflows. Along with various well performance parameters being analyzed, two key parameters for liquid loading debottlenecking, such as critical unloading velocity and the In-situ velocity, are investigated in the IAOM (Integrated Asset Operation Model) system for each well as the function of depth along well's completion. Furthermore, advanced dashboards present the analysis output in an instructive manner, driving user's engineering judgment to take preventive decisions. The Integration of framework with various corporate data sources provides a continuous stream of representative data that is utilized to estimate wells deliverability under the pre-defined operating envelope. As a result of the analysis, gas condensate wells that are suffering from liquid loading were identified using the integrated digital framework. Based on the production history and target monitoring, it was observed that these wells were unable to produce as their expected objectives. Identified wells were run through the production gas rate sensitivity analysis using the analytical tool, and as an outcome, the optimal production rate was calculated. Producing the well below this critical rate causes the In-situ velocity to drop below critical unloading velocity. Additionally, using the tuned and calibrated network model, the operating choke was identified to maintain the stable flow in the well and avoid further liquid loading. This choke size was provided to field operation for implementation and, thus, saved the cost and man-hour spent during the flowing gradient surveys. The case study demonstrates significant production improvements observed for these wells, thereby assisting the operator in reducing cost and time significantly. Using Integration of latest production optimization platforms not only provides tools to identify wells which are currently experiencing liquid loading problem but also healthy wells which might come across liquid loading problem in the course of production, thus helping in taking proactive remedial action. Furthermore, the integrated framework provides erosional velocity related data, which acts as a guideline while optimizing gas production.

Abstract Rigless well commissioning is an important stage of well completion to deliver a new drilled or worked-over wells (oil producer or water/gas injector) ready for production or injection. Rigless well commissioning employs firstly slick wireline intervention for well accessibility verification, down hole safety valve operability, bottom hole pressure and fluid gradient survey that assists to design the flow to clean commissioning program. Secondly, it employs coiled tubing (CT) and flow to clean (FTC) packages to cleanup the well and if necessary to perform matrix acidizing to improve well productivity or injectivity. This paper highlights operational constraints of well commissioning and its effective approach from job design, execution and evaluation that have been performed over 250 wells in the span of 5 years operations. The commissioned wells are drilled in the carbonate formation with surface clustered operation in Onshore and Offshore Artificial Islands. It also describes HSE challenges that have been faced in safe handling of return fluid, management of volatile recovered crude oil, simultaneous operations (SIMOPS) with Drilling Rig, Project and Construction (P&C) activities and hydrocarbon flaring in the environmentally sensitive area. The implemented approach and methodology of well commissioning has evolved significantly to address operational challenges and reducing well commissioning cost by 60%. It proves improvement of operating efficiency of CT and FTC packages based on downhole pressure survey, smart well commissioning, eliminating high risk clean-up operation for injector well, cluster based well commissioning, in-situ return fluid management and arrangement of vertical flare stack in the constraint offshore artificial island. The overall outcomes have achieved technical objective with optimized cost and minimum risk, enhancing rigless package utilization and implementing sustainable and effective field rigless commissioning.

Abstract Objectives/Scope The objective of this paper is to discuss the business implications brought upon by the Internet of Things (IoT) and the opportunities in increasing offshore operations safety, efficiency, and innovation. Methods, Procedures, Process Several operations in offshore production platforms are studied as to determine how can be transformed using IoT and other digital technologies to yield safer and efficient alternatives. The main processes covered in this paper cover well performance optimization, platform maintenance schedules, and means of minimizing human intervention by utilizing robots to perform the routine operations. The proposed initiative is to develop an automounts smart platform able to run safely and efficiently with minimal human intervention. Some of the sensors and actuators that are going to play a big part in this proposition include a wide range from bottom-hole sensors, artificial lift equipment, surface equipment, and up to the first separation stage. Results, Observations, Conclusions The paper aims to establish a roadmap for establishing digitally capable offshore production platforms to minimize human intervention, increase safety, and yield optimum production performance. We layout the roadmap considering the importance of how to ‘Add Value’ by utilizing the digital technology. Three main aspects discussed include how to optimize well performance through real-time choke performance utilizing by all the sensors upstream and downstream, and the actuators, like the choke valve. The integration of well flowing parameters with AI assisted systems for constant evaluation of well performance and abnormality detection is a major and feasible mean of increasing value of these assets. Once a sufficiently large set of data within the IoT umbrella is available for data analytics, then engineers can create innovative ways of handling day to day operations without minimal human intervention. Novel/Additive Information The paper expands on previous knowledge by specifically mentioning areas where integrating IoT is most feasible, with objective of improving offshore production operations to achieve a sustainable, profitable, and safe operation.

Abstract Objectives/Scope Oil production optimization under economical and operational constraints is of paramount importance to most E&P companies. Enhancing production from mature oilfields is often achieved through artificial lift operations. Decline in well performance is observed in most aging giant waterflooded reservoirs in Abu Dhabi. The objective of this paper is to propose an efficient method to improve well performance while optimizing long-term field development plans both for minimum investment and maximum recovery. Methods, Procedures, Process This paper presents a dynamic field management strategy to optimize the gas lift allocation with groups of wells performing under different operational constraints. The gas lift allocation optimization is the cornerstone of the field development plan optimization to increase the recovery from existing wells by applying optimal gas lift injection, to optimize the infill drilling planning to achieve the mandated target, and to minimize the requirements for infill drilling. Despite the large number of gas-lift optimization procedures proposed in the literature, this paper describes a very efficient methodology that is suitable for long-term field developments. In addition to optimization of individual well performance, we propose a new logic for gas lift allocation based upon well potential, history, and performance and the long-term investment planned for the field. This required dynamically to change the logic of allocation mechanism in real-time management manner which proved its efficiency when applied to a giant waterflooded reservoir suffering from water override and high water cut. The method’s logics implemented in terms of fields entities within a simulator field management framework are independent of reservoir model and can be easily scaled and applied to any other reservoir. Results, Observations, Conclusions The implementation of the proposed gas-lift based optimization strategy allowed to achieve the mandated field production by increasing the lifetime of existing wells, while delaying and reducing the number of infill wells. This resulted in a much more economic strategy while minimizing cost and risks of drilling activities. Applying this unique workflow, allow to activate the gas lift optimization function while the field still on plateau, which was not possible before following the default logic in all the simulators. The result showed significant improvement on the field scale in terms of gas lift and facility requirements as well as field production performance. In addition to that, realistic gas lift requirements was observed compared with the conventional methods. Economic analysis is still ongoing, however, huge cost saving is expected and will be presented in the technical paper. Novel/Additive Information In current economic situation, making field development more profitable can be achieved by applying the proposed approach which will help establishing solid foundation to develop fields at scale. This is due to the flexibility and intelligence of the logics applied in the methodology which combine both constraints from operations and uncertainty in the long run. As described, the method is generic and can be applied to other fields following the same workflow steps.

Abstract Proppant flowback from hydraulic fracturing is widespread and costly due to erosion and/or blockage of producing hydrocarbons due to proppant accumulation. One remedy is to install sand control equipment integrated into a sliding sleeve device (SSD) as part of the completion string, which raises concern about erosion during fracturing. While some installations have been successful, at least one experienced sand control failure. Computational Fluid Dynamics (CFD) was deployed to evaluate the root cause and identify more robust designs, as presented herein. Firstly, we identified the most probable causes of sand control failure during multistage fracturing (MSF) in openhole (OH) horizontals. State-of-the-art CFD simulations were then performed on the installed design using actual flow conditions (rates, slurry properties, treatment time) from a failed installation. The static CFD methodology in an initial undeformed geometry proved to be ultra-conservative, so a new quasi dynamic mesh (QDM) methodology was developed, which yielded more realistic (albeit still conservative) erosion-depth predictions. The results revealed areas for improving the design of key components, and CFD was re-run to confirm erosion resistance targets. The modifications were then implemented for a field trial. Since frack location between two openhole packers is unknown, and the frack port is located between multiple screen/SSD assemblies, one must consider annular flow across the assembly in both directions. Accurate CFD predictions of erosion of completion components versus time during MSF in OH proved challenging. The quicker static methods were useful in ruling out some components as problem areas, such as the sand control media, but proved overly conservative on other key components. The QDM methodology gave more realistic results and indicated that erosion depths in specific locations could be deep enough to possibly cause sand control failure. To reduce the erosion risk, such components were modified, and the result was a reduction in predicted erosion depths to acceptable levels. A safety factor was already built into the predictions because of two key conservative assumptions: ignored initially were 1) particle-particle interaction and 2) erosion of the reservoir wall. The former was further investigated. While waiting for the field trial results, the main conclusion thus far is that CFD is a valuable tool for diagnosing erosion failures and improving equipment design. However, it’s essential to use a methodology that realistically captures downhole conditions. Presented herein is a more robust design of a screen/SSD assembly for proppant flowback control, as well as an improved CFD methodology for diagnosing sand control failures during MSF and for identifying design improvements of completion equipment. Furthermore, the inherent challenges of controlling proppant flowback without causing erosion or flow blockage of hydrocarbons are discussed.

Abstract The mature Great Burgan field comprises of more than 2000 wells to date, many of these wells utilize artificial lift in their production to maintain production targets. Tubing leaks and integrity issues pose major challenge to the artificial lift pump; these leaks eventually cause pumps temperatures to exceed the operating limit, trip and stop production. The waiting time for a workover rig is about 4 months, this converts to a significant loss of oil production in every well with tubing integrity issue. To reach and sustain the production target, rigless tubing repair is perceived as a viable quick solution to maintain production until workover rig becomes available.

Abstract The latest well completions developments for extended-reach wells include advanced techniques to improve the effectiveness of production and optimization solutions to achieve sustainable well production. Monitoring systems installed during the completion use real-time distributed temperature sensing (DTS), distributed acoustic sensing (DAS), and downhole gauge data to obtain better reservoir insight throughout the life of the well. This enables informed decision making to achieve optimal well production and gas injection. Permanent downhole gauges (PDGs) with dual sensors (tubing + tubing) are installed, along with hybrid cable as part of the upper completion string. The hybrid cable has an electrical conductor and two fiber-optic lines for DTS and DAS measurements. The cable is clamped onto the tubing at each coupling and passes through the upper completion subassemblies, which include gas lift mandrels (GLMs) and tubing-retrievable safety valves (TRSVs). An intermediate completion is run before the upper completion, which comprises a two-trip permanent packer and remote actuated barrier device (multicycle). Completions monitoring with hybrid cables provides an advantage over conventional gauge-only systems, with only a slight increase in completion costs. Using a single cable provides more run-in-hole (RIH) efficiency, fewer lines to manage, and a smaller equipment footprint. PDG data are used by production engineers, field development personnel, and subsurface personnel to determine pressure drawdown and optimize surface production choke size. Distributed fiber-sensing technology determines the effectiveness of gas lift operations to optimize injection rates, which effectively optimizes pumping rates and flow from surface. Fiber-sensing technology also helps identify tubing and annulus leaks, monitor the health of the completion during the life of the well, and minimize wellbore damage. This type of completion has been installed successfully in 64 wells (60 production and 4 injection), and all systems are operational with data accessible from all wells. This approach benefits the industry by highlighting best practices, providing advanced technology options for evaluating data and reservoir productivity, and providing completion and drilling effectiveness for extended deep-reach wells.

Abstract This paper presents a state-of-the-art, automated gas lifted smart completion design, installed safely using Side Mounted Guns (SMG) to reduce well control risks for a carbonate field in Sarawak with a dominant threat of karst losses. It demonstrates how an SMG system was used to decrease installation time and minimize formation damage. The new 3D finite element software technique represents a step change in the ability to predict shock loading from complicated perforating systems and the subsequent effect on downhole completion components. Several challenges were addressed at the planning phase of the project, including the use of a new 3D finite element software to evaluate dynamic perforating shock loading and determine the optimal distance to safely place the key completion components in the well. A variety of system integration tests (SITs) were also introduced to verify compatibility of the SMG system in highly deviated well conditions and deploying through casing with inner diameter changes. Three wells have been successfully perforated with a long tubing-conveyed SMG system along with the smart well completion components, such as an inflow control valve (ICV), downhole pressure gauges, and seal assembly, which were then tested as fully functional after the gun detonation. During the well cleanup operation, the perforated gas cap was successfully used to lift the oil from the reservoir underneath the gas cap as an in-situ gas lift.