Profitable development of hard-to-recover reserves often involves drilling of horizontal wells with multistage hydraulic fracturing to increase the oil recovery factor. Usually to monitor the fracture sweep efficiency, pressure transient analysis is used. However, in case of several fractures this method delivers only average hydrodynamic parameters of the well-fracture system. This paper illustrates the value of temperature logging data and demonstrates possibilities of the 3-D thermo-mechanical modelling in evaluating the differential efficiency of multi-stage hydraulic fracturing.

A novel electromagnetic instrument is presented that uses transient or pulsed eddy current measurements to perform quantitative evaluation of downhole corrosion in four concentric tubulars individually, and to inspect a fifth tubular qualitatively. Case studies are presented that compare results from this instrument with industry-standard single-string evaluation tools such as multi-finger calipers and high-resolution magnetic flux leakage tools. The new instrument is based on transient or pulse eddy current technology and comprises three highly sensitive sensors that simultaneously achieve high-resolution of the inner barrier and high radial depth of investigation for up to five barriers. Each sensor induces coaxial rings of eddy currents in multiple concentric tubulars and measures a time-varying response from the outward-diffusing eddy currents. The full transient responses from multiple sensors are then interpreted to obtain individual tubular thickness profiles. Case studies are presented where the thickness profiles of outer barriers are obtained with the new instrument and are compared with high-resolution benchmark logs of multi-finger calipers and magnetic flux leakage tool. The benchmark logs were measured when the outer barrier was directly accessible because, either the inner barriers were not yet present, or the inner barriers were removed. These comparisons show that the new electromagnetic instrument is able to provide accurate individual tubular corrosion evaluation while logging through tubing. This ability is invaluable for proactive well integrity management because electrochemical corrosion, which is the primary corrosion mechanism in these wells, causes the outermost casing to fail first and then continues to penetrate inwards. Therefore, the new electromagnetic instrument enables early diagnosis of the outer tubulars to identify potential weak zones in the completion string while logging through tubing and eliminating the cost of pulling completions for this purpose. This paper describes the advantages and limitations of state-of-the-art multi-sensor pulsed eddy current measurements for individual barrier thicknesses of four or five strings. New case studies with high-resolution magnetic flux leakage tools and multi-finger calipers support these conclusions.

Rate testing has evolved over the years. From a simple composite separator system, the scope of rate testing has morphed into a broad spectrum of sophisticated downhole and surface technologies. Knowing well behavior, performance, and associated rate are the key factors of operating an entire field with the most reliable operating strategy, assuring maximum well-life time. In regard to well modeling and optimization, valid rate test data are crucial to predict well performance efficiently. An in-house rate testing mechanism was developed to ensure proper delivery, accuracy, and validity of rate tests. The mechanism comprises a rate testing procedure and decision-making tree. The rate testing procedure includes regular checks of rate testing data reports. Also, the immediate resolution of rate testing equipment or communication issues is implemented through the utilization of an MPFM Advanced Monitoring System with automated logics. A decision-making tree constitutes pre- and post-testing process phases. The pre-testing process phase involves an assessment for rate testing readiness in terms of testing equipment and communication. The post-testing process phase includes an assessment for testing operation and rate test validity where rate test data are checked and validated based on production operational status. The enhanced testing mechanism is a user-friendly guideline for testing requirements to ensure the completion of tests captured from testing equipment. The proper implementation of this rate testing mechanism enabled a high quality and accuracy of rate test data, resulting in an increase in rate testing validity by 30%. Also, the rate testing mechanism inspired a culture of continuous effective communication for all involved parties during the testing operation. The decision-making tree transforms the validation process from subjective thinking to a systematic workflow while integrating data from nearby wells with similar behavior. A high ownership level is exhibited by taking the immediate resolution of issues results in achieving high rate testing validity percentage. Running the process through standardized operating procedures is critical in generating consistent and predictable results of well performance. Additionally, accurate optimization and prediction of well performance have been realized by feeding the well model's data before and after attaining valid rate test data, which attests to the quality of the proposed rate testing mechanism. Considering the importance of having a strategic rate testing mechanism, it is highly advised to have more frequent measurements to raise the accuracy of the measurements presented. An ideal strategic rate testing mechanism has to be economical enough to be placed in many production wells, allow the tests to be performed in an organized manner, improve measurement accuracy, and, more importantly, achieve automated and supervised well tests processes.

Several techniques have been applied to improve fluid conformance of injection wells to increase water flooding performance and eventually field oil recovery. Normal outflow control devices (OCDs) are effective solutions for this problem in reservoirs with static properties, however, they fail in reservoirs with complex/dynamic properties including fractures. There, the continuously increasing contrast in the injectivity of a section with the fractures compared to the rest of the well causes diverting a great portion of the injected fluid into the thief zone thus creating short-circuit to the nearby producer wells. This paper summarizes the integrated technical learnings from the successful application of the installation of the first Autonomous Outflow Control (AOCD) technology in a new long horizontal injector well. It shows the result of extending this technology to other injectors in both water and polymer phases in the field, it details the facts and observations and the insights the multidisciplinary authors have captured. This autonomously reactive control on the injection fluid conformance resulted in an increased sweep and ultimate oil recovery while reducing the total volume of injected fluid.

This paper describes the procedure to perform a fluid caliper and how by using fluid dynamics concepts, average hole size can accurately be determined, helping to derive the amount of hole washout and the appropriate amount of cement needed to circulate or achieve desired cement height. This process has been successfully performed on over 40,000 Permian Basin wells in West Texas and Eastern New Mexico, as well as numerous other basins in the United States. This includes vertical, directional, and horizontal wells of varying hole sizes and depths, from surface to production hole. This paper will provide real world examples, discussion of geological formations encountered, drilling fluids used, and the ultimate benefit a fluid caliper provided each operator through the accurate estimation of cement volume for the reduction of waste and satisfaction of well design and regulatory requirements. This paper will demonstrate that fluid calipers add to the operational efficiency of most drilling operations and should be considered a "Best Practice" for most drilling programs as their use can greatly limit the need to remediate a cement job necessitating additional downhole tool runs, wasting additional valuable rig time. Also, to be addressed are the limitations of fluid calipers including lost circulation, turbulent flow, and human error. Cementing is an integral part of the process to ensure wellbore longevity, requiring increased attention. Field practice of pumping nut plug, dye, or other markers to estimate required volumes is outdated and inaccurate. This paper will clearly identify the reasons why the modern fluid caliper is aligned with today's heightened focus on ESG. Environmentally, fluid calipers determine the proper amount of cement to prevent waste. Regarding safety, fluid calipers help ensure the operator pumps accurate cement volumes to cover corrosive and/or productive zones to prevent unwanted annular influx, and referring to governance, fluid calipers help the operator pump adequate cement volumes to satisfy well construction regulations.

Air-water two-phase flow in circular pipes has been studied by many investigators. However, investigations of multiphase flow in non-circular pipes are still very rare. Triangular pipes have found a number of applications, such as multiphase flow conditioning, erosion mitigation in elbows, compact heat exchanges, solar heat collectors, and electronic cooling systems. This work presents a survey of air-water and air-water-sand flow through circular and triangular pipes. The main objective of this investigation is to study the potential effects of triangular pipe geometry on flow patterns, slug frequency, sand erosion in elbows, and heat transfer in multiphase flow. Firstly, twenty-three experiments were performed for horizontal air-water flow. Detailed videos and slug frequency measurements were collected through circular and triangular clear pipes to identify flow patterns and create a database for these pipe configurations. The effect of corners of the triangular pipe on the liquid distribution was investigated using two different orientations of triangular pipe: apex upward and downward and results of triangular pipes were compared to round tubes. Secondly, ultrasonic wall thickness erosion measurements, paint removal studies, and CFD simulations were carried out to investigate the erosion patterns and magnitudes for liquid-sand and liquid-gas-sand flows in circular and triangular elbows with the same radius of curvature and cross-sectional area. Thirdly, heat transfer rates for liquid flows were also simulated for both circular and triangular pipe cross-sections. Although similar flow patterns are observed in circular and triangular pipe configurations, the orientation of the triangular pipes seems to have an effect on the liquid distribution and slug frequency. For higher liquid rates, slug frequencies are consistently lower in the triangular pipe as compared to the circular pipe. Similarly, the triangular elbow offers better flow behavior as compared to circular elbows when investigated numerically with similar flow rates for erosion patterns for both liquid-sand flow and liquid-gas-sand flows. Experimental and CFD results show that erosion in the circular elbow is about three times larger than in the triangular elbow. Paint studies results validated erosion patterns and their relations with particle impacts. Finally, heat transfer to/from triangular pipes is shown to be more efficient than in circular pipes, making them attractive for compact heat exchangers and heat collectors. This paper represents a novel experimental work and CFD simulations to examine the effects of pipe geometries on multiphase flow in pipes with several practical applications. The present results will help to determine the efficiency of utilizing triangular pipes as compared to circular pipes for several important applications and field operations such as reducing slug frequencies of multiphase flow in pipes, and reducing solid particle erosion of elbows, and also increasing the efficiency of heat exchangers.

Well network simulation and optimization is an established technology within BP for production optimization. However, for simplicity, the processing facilities are usually only considered as fixed oil, gas and water flow rate constraints. Actual production limits vary as a function of operating conditions and/or cannot be measured directly (e.g. True Vapour Pressure (TVP) or gas velocity at the inlet separator nozzles). To improve on existing workflows, BP has expanded its existing petroleum engineering-focused toolkit and is now globally deploying an end-to-end production system digital twin that extends from the well choke to the facility export for system surveillance and optimization. The end-to-end production system digital twin is a cloud-based system that links sensor data from the asset historian with an equipment data model and third-party first principle steady state simulation tools for an accurate representation of the well network and processing facilities. It supports multi-discipline collaboration, particularly between Petroleum Engineers and Process Engineers, and is remotely accessible by a globally dispersed team. This integrated digital twin can be used in two modes: monitoring and what-if. In monitoring mode, the models are automatically updated hourly with real time data and key simulation results extracted and stored. These monitoring simulations generate virtual sensor output, providing insights that cannot be measured by real sensors. In what-if mode, engineers test scenarios risk-free to explore optimization opportunities. As well as routine optimizations to align with production forecast updates, this can also include scenarios during planned abnormal operations (e.g. facility equipment offline for maintenance or well flowback). An early pilot in a key production region delivered significant production upside and was foundational for the subsequent global roll-out program. This paper will illustrate two practical applications from early deployment activities: (1) condensate recovery optimization (2) well routing optimization / feasibility against variable processing facility limits.

Sludge formation could significantly impair well productivity if deposited in the wellbore or surface flow lines. In a field where sludge formation is not common, an oil production well showed a sudden deterioration in well productivity. Thorough investigation of abnormal well performance, from surface and sub-surface perspective, indicated that the deposition of a thick layer of a tight emulsion across the surface choke has resulted in ceasing the oil flow to the gas oil separation plant. Extensive lab analysis indicated that the obstruction material was a sludge deposition promoted by the presence of asphaltene, high amount of iron and low pH brine. It is noteworthy to mention that the analytical results of lab prepared emulsion samples elucidate the rule of low pH aqueous solution, asphaltene and iron ions in inducing tight emulsion formation which helps to understand the root causes of sludge deposition. To come up with a cost-effective remedial treatment considering health, safety and environment (HSE), different emulsion breaking formulations, including different de-emulsifiers and anti-sludge agents, were examined in this study. An effective diesel-based formulation including proper de-emulsifier and anti-sludging agent was used during the execution of the field job. The design of the field job took into consideration a minimal footprint to the environment through the flowback of the well to the neighboring gas oil separation plant. This paper summarizes the joint efforts by production engineers and lab scientists to systemically tackle such major flow assurance issues which could significantly jeopardize wells productivity. The systemic approach starts with problem detection through well intervention and sample collection. It also includes the lab work which was carried out to identify the type and composition of deposition and evaluate/optimize a proper formulation for sludge deposition removal. The paper discusses in detail the design and execution of a successful field treatment, which has resulted in restoring and maintaining the well potential.

This paper describes an innovative solution for the safe and effective management of wells with unplanned sustained annulus pressure (SAP). The solution restores double barrier integrity in the well and provides reliable real time annulus pressure and temperature data. It also has the functionality to autonomously bleed-off the annulus pressure at a pre-determined set point. As a result, the nature and severity of the SAP can be better understood, and in many cases wells that would otherwise have been closed in awaiting workover can remain in production.

Objective/ Scope Production logging analysis is essential to understand and evaluate reservoir performance throughout the lifetime of an oil well. Data acquisition and analysis is known to be challenging in modern extended reach horizontal wells due to multiple factors such as conveyance difficulties, fluid segregation, debris, or open hole washouts. Advanced compact multiple array production logging tool (APLT) is proposed to minimize the uncertainties related to these challenges. Method, Procedure, and Process The proposed sensor deployment method provides a comprehensive borehole coverage, thus maximizing the amount of subsurface information collected to evaluate the production performance of a horizontal well. Essential measurements are combined on six individual arms. Each arm is independently deployed which guarantees the best borehole coverage in a variety of borehole condition. Robust mechanical arm design minimizes damage, allows tolerance to decentralization, and provides greater confidence in determining the sensor locations. Each arm utilizes two fluid holdup sensors (Resistance, Optical) and one velocity sensor (Micro-Spinner). Co-location of the sensors minimizes the uncertainty related to sensor spacing when compared with previous generation of APLT. Results, Observations, Conclusions The new sensor deployment method and analysis results are discussed showing the added value in barefoot completion as well as advanced ICD completion. The holdup sensors response from previous generation APLT is compared to the advanced tool and how it relates to better borehole coverage. The results also illustrate use of high frequency optical probes for phase holdup determination. In addition, the optical probes are used to confirm bubble point pressure at in situ conditions by confidently detecting the first gas indication in the tubular. The results clearly show how a compact APLT maximizes the borehole coverage in highly deviated and horizontal wells. This is critical in collecting representative data of all segregated fluids which enables more accurate interpretation of the flow profile in the well and better understanding of reservoir performance. Novel / Additive Information The novelty of the new instrument is the ability to maximize the amount of subsurface production logging information collected with low uncertainty and minimum operational risk.

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.

The paper discusses the pilot project in ADNOC Offshore to assess the Autonomous Inflow Control Device (AICD) technology as an effective solution for increasing oil production over the life of the field. High rate of water and gas production in horizontal wells is one of the key problems from the commencement of operation due to the high cost of produced water and gas treatment including several other factors. Early Gas breakthrough in wells can result in shut-in to conserve reservoir energy and to meet the set GOR guidelines. The pilot well was shut-in due to high GOR resulted from the gas breakthrough. A pilot project was implemented to evaluate the ability of autonomous inflow control technology to manage gas break through early in the life of the well spanned across horizontal wellbore. And also to balance the production influx profile across the entire lateral length and to compensate for the permeability variation and therefore the productivity of each zone. Each compartment in the pilot well was equipped with AICD Screens and Swell-able Packers across horizontal open hole wellbore to evaluate oil production and defer gas breakthrough. Some AICDs were equipped with treatment valve for the compartments that needed acid simulation to enhance the effectiveness of the zone. The selection factors for installing number of production valves in the pilot well per each AICD was based on reservoir and field data. Pre-modeling of the horizontal wellbore section with AICD was performed using commercial simulation software (NETool). After the first pilot was completed, a detailed technical analysis was conducted and based on the early production results from the pilot well showed that AICD completions effectively managed gas production by delaying the gas break through and restricting gas inflow from the reservoir with significant GOR reduction ±40% compared to baseline production performance data from the open hole without AICD thus increasing oil production. The pilot well performed positively to the AICD completion allowing to produce healthy oil and meeting the guidelines. The early production results are in line with NETool simulation modelling, thereby increasing assurance in the methods employed in designing the AICD completion for the well and candidate selection. This paper discusses the successful AICD completion installation and production operation in pilot well in ADNOC Offshore to manage GOR and produced the well with healthy oil under the set guidelines. This will enable to re-activate wells shut-in due to GOR constraint to help meeting the sustainable field production target.

Over the past decade, coiled tubing (CT) has been one of the preferred fluid conveyance techniques in tight carbonate oil producers completed with an uncased horizontal section. In the onshore Middle East, conventional CT stimulation practices have delivered inconsistent results in that work environment. This is mainly due to a mix of reservoir heterogeneity, limited CT reach, lower CT pumping rates, uncontrolled fluid placement, and uncertainty of downhole dynamics during the stimulation operations. An intervention workflow recently validated in onshore Middle East to acidize tight carbonate openhole horizontal water injectors was introduced for the first time in an oil producer. The advanced stimulation methodology relies on CT equipped with fiber optics to visualize original fluid coverage across the openhole interval through distributed temperature sensing (DTS). Real-time downhole telemetry is used to control actuation of CT toolstring components and to understand changing downhole conditions. Based on the prestimulation DTS survey, the open hole is segmented into sections requiring different levels of stimulation, fluid placement techniques, and diversion requirements. The candidate carbonate oil producer featured an average permeability of 1.5 md along 8,003 ft of 6-in. uncased horizontal section. Because of the horizontal drain's extended length and the presence of a minimum restriction of 2.365-in in the 3 1/2-in. production tubing, a newly developed CT slim tractor was essential to overcome reach limitations. In addition, a customized drop-ball high-pressure jetting nozzle was coupled to the extended reach assembly to enable high-energy, pinpoint acidizing in the same run. The instrumented CT was initially run until lockup depth, covering only 53% of the horizontal section. The CT slim tractor was then precisely controlled by leveraging real-time downhole force readings, enabling full reach across the open hole. Prestimulation DTS allowed identification of high- and low-intake zones, which enabled informed adjustments of the acidizing schedule, and in particular the level of jetting required in each section. After its actuation via drop-ball, the high-pressure jetting nozzle was operated using downhole pressure readings to ensure optimum jetting conditions and avoid exceeding the fracturing threshold. Upon completion of the stimulation stage, post-stimulation DTS provided an evaluation of the fluid placement effectiveness. After several weeks of production, the oil rate still exceeded the operator's expectations fivefold. This intervention validates the applicability of the advanced matrix stimulation workflow in tight carbonate oil producers completed across a long openhole horizontal interval. It also confirms the value of real-time downhole telemetry for optimal operation of extended reach toolstrings and the understanding of the downhole dynamics throughout stimulation treatments, the combination of which ultimately delivers breakthrough production improvements compared to conventional stimulation approaches, in a sustainable manner.

Slugging is an ongoing flow assurance risk in some of the ADNOC Onshore production systems, leading to difficulty in operations, inefficiencies, integrity and HSE concerns. For example stagnant water increases the risk of pipeline corrosion, especially with increased levels of H2S and CO2, potentially leading to leaks, pressure rating downgrading and reduction in the overall system capacity. With more reservoirs being under different schemes of secondary and tertiary recovery (WI, WAG, EOR – CO2, etc.), slugging in wells and transfer lines is expected to continue to be a challenge for the efficient and safe production operations across the entire ADNOC Onshore. This paper summarizes an integrated approach to understand the underlying causes of slugging in an onshore production system, reviews the current slug mitigation philosophy and proposes a stepwise approach to improve performance of the system, leading to production acceleration, improved profitability, efficiency and HSE performance. The system under investigation is experiencing slugging in the Transfer Line (TL) leading to liquid surges in the first stage separator (SEP) located at the Central Facilities. The slugging in the Transfer Line is attributable to a combination of wells and terrain induced slugging, and not so much to the hydrodynamic effects of the multiphase flow. In the current slug management philosophy, the pressure (RP) recorded at the TL receiver location is used in an algebraic formula to calculate a level set-point (LSP) that, in relation to the actual oil level in the separator (SEP), is used to act on the Surge Control Valve (SCV) located at the separator inlet. When the LSP is below the actual oil level in the separator, the SCV is tripped to 30% opening. The RP signal acts as a tell-tale sign of the incoming slug. In an initial phase, the system performance is evaluated using real time data available in the Control Room and offices. The initial data driven approach is complemented by complex dynamic multiphase modeling efforts. The models are used for further insights into the system behavior under different operational conditions, with a focus on identifying a more stable operating envelope, where the effects of slugging are mitigated while the production levels are maintained or increased. The focus on this paper is on the interface between the Transfer Line (TL) and inlet separator (SEP), including the Slug Control Valve (SCV). Results indicate a more stable flow regime is achieved at higher fluid velocities in the TL, where the RM pressure is increased to 35 barg from the current 29 barg. (N.B. The 35 barg is the maximum TL operating pressure, as identified in a separate study, and limited by the current HIPPS setpoints. The corresponding increase in production capacity is up to 10,000 bopd, thus accelerating the cumulative oil by up to 3.5 MMBBl / year, and accelerating revenue by up to USD 180 MM / year). However, in the current control scheme, operation at 35 bar is limited by the SCV characteristic and control scheme. To mitigate the problem, a staggered approach is proposed. A reduction in SCV tripping frequency is expected to be achieved in the short term, by modifying the algebraic equation that govern the SCV actions. A slight increase in the B factor by 2.5% is expected to reduce the SCV tripping frequency by up to 10%. Reduction in SCV tripping frequency will further reduce the mechanical stress on the valve and associated piping, thus reducing the risk of structural damage of the system. Also, it will allow for starting to increase the fluid velocities and move towards a more stable flow regime and reduced water holdup in the pipeline (reduced corrosion risk). Additional increase in fluid velocities appears to be limited by the SCV characteristic. In the current control scheme the pressure drop across the valve becomes sizeable at higher flowrates, leading to frequent tripping. As a longer term measure, increasing the SCV capacity is expected to facilitate operation of the system at higher fluid velocities, thus reducing the slugging, mechanical stress and corrosion risk in the TL. As slugging will continue to be a challenge to safe and efficient operations across ADNOC Onshore, it is important to develop in house the ability to understand the underlying causes for such flow instabilities, identify mitigation and optimization workflows. This paper demonstrates that a combination of data driven analytics and integrated physics based modeling, carried out in an integrated approach by a mixed team of subsurface and surface engineers, can help understanding the system behavior under slugging conditions and identify opportunities to improve production system efficiency and profitability, while operating within a safer envelope.

Well completion has evolved rapidly in the past two decades, as multistage completion has become the predominant practice to complete a well in many places. Although innovation in completion tool technology has been continuous in recent years, there are still gaps in the well completion optimization practice. In this paper, we add additional dimensions to well completion technology by incorporating geoengineering, measurement while pumping, and data mining, and we have evidence to show that those additional elements help to improve our understanding, on-site efficiency, and overall performance. Multistage completion optimization is about where and how to complete a well. Different methods were employed in the past, and even with a better-engineered completion design where both reservoir and completion quality are honored, there are still area for improvement. For example, 1) geological properties are not qualitatively utilized in the completion design; 2) real-time operational feedback during the execution phase is inadequate for in-time decisions for completion and fracturing adjustment; 3) the completion-to-well-performance cycle is so long that the learning curve is not fast enough, and too many influential factors are hidden in the details. Three extra dimensions were added to address the improvement areas. Geoengineering adds "space information" in enabling geological properties from a 3D space grid to be projected onto the wellbore as geology quality (GQ) so that the information can be used together with reservoir and completion quality (RQ and CQ) quantitatively to improve the fracturing treatment design. Measurement while pumping (MWP) adds "timely feedback" in that real-time operational feedback—either from the wellbore via high-frequency pressure monitoring or from the target zones via microseismic data in offset horizontal monitoring wells—can help with the completion and fracture diagnosis and decision making on-site. Data mining adds "pattern recognition" in that reservoir and operation data are collected and analyzed to generate a systematic understanding of the reservoir complexity, paving the way for the improved planning of future well completions in the same region. Each of the solutions comes with specific case studies in our work. Geoengineering, MWP, and data mining add three dimensions to the current well completion practice. In our case studies, these approaches have demonstrated the capability to improve the accuracy of the design, increase confidence in the execution, and accelerate the learning curve from evaluation. The extra dimensions added to the current completion practice are essentially space, time, and pattern, and together, they help to define the direction of future innovations for completion optimization.

This paper represents a challenging rig-less intervention in highly deviated wells with heavy oil that has always been a challenge to conventional electric line (e-line) that is not a valid intervention technique due to its inherent limitations in these harsh environments. Electric Coiled Tubing (E-CT) was utilized not only to achieve safer deployment of the guns, but also to allow real-time operations on three wells which were inaccessible due to heavy oil content and restricted e-line accessibility. A case study is presented for a campaign performed using E-CT to convey the perforating string while pumping nitrogen (N 2 ) to lift the well and achieve flowing under-balance to maximize perforation clean-up and minimize skin. Real-time readings from gamma ray, pressure and temperature sensors were used to accurately position the guns, generate the desired dynamic underbalance, and finally validate successful detonation based on pressure and temperature responses. This was achieved while N2 lifting and firing the guns to optimize the required under-balance value providing immediate feedback related to the production gain to determine the zonal contributions and maximize the economical production gains. Dynamic wellbore behavior software modeling was also used to predict the dynamic under-balance effect for maximizing perforation efficiency. Deployment of E-CT was very challenging in terms of operational execution but was extremely beneficial for the safety of the pipe during such operations. A total of 13 runs comprising of milling, tubing cleaning and drifting were performed to remove the accumulated scales inside the production tubing and to ensure full accessibility to target intervals. Coiled Tubing (CT) dynamic modeling software was utilized to simulate the N2 rate needed to achieve the target underbalance while maintaining safe perforating parameters for the CT while firing the guns. As a result of software simulations, one of the three wells was then recommended for an acid wash treatment which achieved very effective results. 15 perforation runs were performed on the three wells re-perforating a total of 188 ft of interval, resulting in a production increase of more than 300%. This was a significant improvement compared to the previous campaign carried out in 2017 where perforating in static conditions showed no increase in production without work-over rig intervention. E-CT intervention also eliminated the need for waiting on rig schedule and avoiding deferred production.

Challenges in the design of efficient EOR field pilots have been discussed and documented in the industry, particularly when it comes to optimization of monitoring plans for technical and economical perspectives. This paper explores the benefits of pilot planning where the monitoring/control strategies are included in the early stages of the design to reduce risk of measurements ambiguity and ensure good quality pilot results evaluation. It addresses the use of new and existing technology in monitoring by highlighting the advantages and challenges of each alternative including potential pairing of complementary options to achieve the pilot objectives including illustration of the use of continuous and sporadic measurements on the evaluation. The proposed approach starts with a review of reservoir performance, heterogeneity and pilot objectives to ascertain the plausible monitoring technologies/strategies to aid during the pilot de-risking, followed by the identification of adequate novel and mature monitoring options, which are specific to EOR type and measurement nature (permanent, time lapse, etc.). Advantages of incorporating the monitoring strategy as integral part of the pilot design, as well as evaluation of the effectiveness/viability in the presence of uncertainty of the selected monitoring alternatives are discussed providing a reference of suitable/plausible EOR specific technologies. The paper illustrates the importance of selecting monitoring alternatives that feed off each other and the importance of using fit-for-purpose evaluation algorithms and a digitally enabled, structured approach to analyze and democratize pilot results and enable actionable decisions in operations.

Several techniques have been applied to improve the water conformance of injection wells to eventually improve field oil recovery. Standalone Passive flow control devices or these devices combined with Sliding sleeves have been successful to improve the conformance in the wells, however, they may fail to provide the required performance in the reservoirs with complex/dynamic properties including propagating/dilating fractures or faults and may also require intervention. This is mainly because the continuously increasing contrast in the injectivity of a section with the feature compared to the rest of the well causes diverting a great portion of the injected fluid into the thief zone which ultimately creates short-circuit to the nearby producer wells. The new autonomous injection device overcomes this issue by selectively choking the injection of fluid into the growing fractures crossing the well. Once a predefined upper flowrate limit is reached at the zone, the valves autonomously close. Well A has been injecting water into reservoir B for several years. It has been recognised from the surveys that the well passes through two major faults and the other two features/fractures with huge uncertainty around their properties. The use of the autonomous valve was considered the best solution to control the water conformance in this well. The device initially operates as a normal passive outflow control valve, and if the injected flowrate flowing through the valve exceeds a designed limit, the device will automatically shut off. This provides the advantage of controlling the faults and fractures in case they were highly conductive as compared to other sections of the well and also once these zones are closed, the device enables the fluid to be distributed to other sections of the well, thereby improving the overall injection conformance. A comprehensive study was performed to change the existing dual completion to a single completion and determine the optimum completion design for delivering the targeted rate for the well while taking into account the huge uncertainty around the faults and features properties. The retrofitted completion including 9 joints with Autonomous valves and 5 joints with Bypass ICD valves were installed in the horizontal section of the well in six compartments separated with five swell packers. The completion was installed in mid-2020 and the well has been on the injection since September 2020. The well performance outcomes show that new completion has successfully delivered the target rate. Also, the data from a PLT survey performed in Feb 2021 shows that the valves have successfully minimised the outflow toward the faults and fractures. This allows achieving the optimised well performance autonomously as the impacts of thief zones on the injected fluid conformance is mitigated and a balanced-prescribed injection distribution is maintained. This paper presents the results from one of the early installations of the valves in a water injection well in the Middle East for ADNOC onshore. The paper discusses the applied completion design workflow as well as some field performance and PLT data.

Fouling of heat exchangers and production of stable emulsions in desalting units can present significant challenges in refinery operations. Often these difficulties occur due to the concurrent processing of two or more crude oils that are incompatible under process conditions. This paper describes a significant development in laboratory techniques for studying these issues and evaluating mitigation strategies. Asphaltenes compatibility was evaluated for oil mixtures that may be co-processed in the refinery using a deposition flow rig, and the results were compared with those obtained with more conventional tests: blending stability analysis by light scattering and various screening methods. The flow rig mimics the process conditions (elevated pressure, high temperature, flow-induced shear) and identifies whether deposition or precipitation will occur. The former can cause fouling of heat exchangers whereas the latter produces solids that can stabilize emulsions in the desalter. By varying the proportions of oils that were co-injected into the deposition flow rig, the range within which mixtures were unstable was found. By flowing through a capillary (to mimic a heat exchanger) and in-line filter, it was possible to identify whether precipitation of suspended flocs or fouling of the heat exchanger itself was the likely issue for each mixture. Emulsion-stability tests were conducted using a pressurized rig with an ersatz separator to mimic the desalting unit; results were compared with those obtained in conventional, ambient-pressure bottle tests. Oil(s) and refinery wash water were injected, mixed under representative shear, and allowed to separate within the typical residence time of the desalter. Chemical additives were tested to identify those that were effective at controlling any observed problems. Results obtained in either flow rig (using representative pressure, temperature, and shear) did not always match those obtained using conventional methods. Asphaltenes fouling occurred under conditions where it was not predicted by screening tests that were conducted at conditions not representative of the process and did not occur under conditions where it was predicted. Differences were also observed between the emulsion stability observed in bottle versus rig tests, though these should be viewed as complementary techniques. This paper presents new laboratory techniques for the prediction and prevention of refinery fouling and emulsion stability. They mimic conditions in the facilities much better than those typically used to date.

The objective of this paper is to demonstrate how both Distributed Acoustic Sensing (DAS) and Distributed Temperature Sensing (DTS) data, acquired using a fiber-optic cable installed and cemented behind a 7" production casing, could be used for single-phase production allocation in two conventional oil producers in the South of the Sultanate of Oman. DAS data can be processed, time-averaged, and filtered to specific frequency bands, to identify and monitor the acoustic frequencies that are excited by the flow through the perforation tunnels. It will be shown that under certain assumptions, the flow-induced acoustic amplitudes at the perforations can be calibrated and converted into actual flow rates, which allows for continuous production profiling across all intervals of interest. DTS data, acquired under transient conditions, can also be analyzed using a thermal simulation model, to allocate production to specific perforation intervals, provided an appropriate logging program is followed. DTS is not as good as DAS in capturing dynamic changes to the inflow profile, but does have a deeper depth of investigation and is less sensitive to the geometry of the perforation tunnels or possible flow obstructions in the wellbore. The two technologies are therefore complimentary and are best acquired simultaneously. This is the first case study in the Sultanate of Oman, where both DAS and DTS data sets were successfully acquired and interpreted for single-phase production profiling in a conventional oil producer with perforated casing. Moreover, it was also the first time in Oman that oriented perforation was achieved with full shot density, through a double perforation run with a slight offset in orientation angle between the two runs.