The consequences of sand production are often disadvantageous to the short and long-term productivity of the well. Although some wells routinely experience controllable sand production, these are the exception rather than the rule. Sand production and its management over the life of the well is not an attractive situation but is often essential to extract the resource. Knowing the root cause behind sand inflow in a well and the possible results can inform an appropriate strategy to safely extract as much of the resource as possible. The sands in such reservoir units often have high permeability and are mechanically weak and prone to sand production. The producing wells are often completed with gravel-packed completions for efficient sand control. Most of the wells have multi-zone completions for better productivity but this further complicates reservoir characterization. This paper describes the first use of downhole sand impact detection technology in such fields. The sand detection technology integrates the fully digitized high-resolution acquisition with signal processing and interpretation algorithm to enhance the sand particle detections as small as 0.1 mm in diameter and up to 1,500 impacts per second. The tool is designed to immune the sensors from any background noise and gas/liquid jetting effect. A combination of production logging tools (PLT) and the sand impact detection tool, was used to understand four phase zonal contributions (gas, oil, water and sand) and pinpoint sand entry in these cases. Results exceeded expectations and the ability for the sand detection tool to accurately detect the point of sand entry enabled immediate intervention to eliminate sand production in these case studies. One of them also resulted in increased production of 7.4kb/d oil without any sand flow and with greatly reduced gas-oil ratio as compared to pre-intervention production. The work clearly demonstrates the practical and effective use of downhole sand impact detection with new sand detection technology to identify and isolate sand production in wells. The innovative tool design makes it feasible to detect even small sand particles in adverse wellbore conditions and varied production rates, thus adding a detection of the fourth phase in an otherwise three phase production log.

This paper introduces a novel technique that allows real-time injection monitoring with distributed fiber optics using physics-informed machine learning methods and presents results from Clair Ridge asset where a cloud-based, real-time application is deployed. Clair Ridge is a structural high comprising of naturally fractured Devonian to Carboniferous continental sandstones, with a significantly naturally fractured ridge area. The fractured nature of the reservoir lends itself to permanent deployment of Distributed Fiber Optic Sensing (DFOS) to enable real-time injection monitoring to maximise recovery from the field. In addition to their default limitations, such as providing a snapshot measurement and disturbing the natural well flow with up and down flowing passes, wireline-conveyed production logs (PL) are also unable to provide a high-resolution profile of the water injection along the reservoir due to the completion type. DFOS offers unique surveillance capability when permanently installed along the reservoir interface and continuously providing injection profiles with full visibility along the reservoir section without the need for an intervention. The real-time injection monitoring application uses both distributed acoustic and temperature sensing (DAS & DTS) and is based on physics-informed machine learning models. It is now running and available to all asset users on the cloud. So far, the application has generated high-resolution injection profiles over a dozen multi-rate injection periods automatically and the results are cross-checked against the profiles from the warmback analyses that were also generated automatically as part of the same application. The real-time monitoring insights have been effectively applied to provide significant business value using the capability for start-up optimization to manage and improve injection conformance, monitor fractured formations and caprock monitoring.

Multiple leaks in production tubing of deep wells can be efficiently identified using fiber-optic distributed temperature measurement and thereby mitigating the health, safety and environment (HSE) risk associated with a potential well barrier failure. Further, a production log can be used to gain more insight and finalize a way ahead to resolve the issues of the well integrity. An innovative solution-driven approach was identified with fiber-optic distributed measurement playing a key role. Multiple leaks were suspected in the production system and a fiber-optic cable was run to identify possible areas of leak path. In these deep wells, after the fiber-optic data acquisition, a production log was recorded across selective depths to provide more insights on leak paths. Post identification of leak depths, a definitive decision between tubular patching and production system overhaul was decided based on combined outputs of fiber-optic, production log and tubular patch technology. Results are presented for a two-well operation. Taking an example of Well A, leaks were successfully identified at three depths using the novel operational approach. Further, operation time was reduced from three days (conventional production log measurement performed during daylight operation) to one day (combination of fiber-optic distributed temperature sensing and production log in a single run). Diagnosis of production system issues were completed in one flowing and one shut-in survey condition, thereby reducing the risk of HSE exposure with multiple flowing conditions (conventional production log measurement). Additional insight and confirmation on leaks were observed from production log data which helped identify the presence of a leak across the tubing body. This observation was substantial in deciding whether to proceed with tubing patch or replace the entire production tubing. Tubing patch technology was not satisfactorily recognized to provide well integrity across leak depths. Hence, the decision was made to replace the entire production tubing. The novel operational approach affirms the versatility of fiber-optic distributed temperature measurement in solving critical issues of operation time and reducing HSE exposure while delivering decisive information on production system issues. The paper serves as a staging area for other applications of similar nature to unlock even wider horizons for distributed temperature sensing.

Assessment of coating performance under flowing condition by using a proprietary flow loop system has been established. The 2 3/8" flow loop was designed to maintain a flow rate of 0.03-0.04 m 3 /sec, pressure of 3300kPa and temperature of 150°C to simulate actual field condition. Test section consisting of two 35" straight tubes with 45° elbow was internally coated and connected to the flow loop which was run continuously for 14 days with deionized water under the specified test condition. Upon completion, visual inspection, EIS and linear abrasion test were done on the test section to evaluate the coating integrity post exposure. Small blisters were noted at the elbow section potentially due to the improper surface preparation and/or higher fluid velocity at the bend section. Impedance value of 10 7 Ω/cm 2 is a magnitude higher than the acceptance limit of 10 6 Ω/cm 2 while abrasion resistance was found less than the set limit of <100mg/1000 cycles. The flow loop test has been shown to be a reliable tool to evaluate the effect of wall shear stress and fluid erosion on internal tubular coating.

A reservoir with a rare geomechanical setting of higher stresses at shallower depths and vice versa was fractured. The multistage fracture responses were validated using production logging data. Further, production optimization was achieved by understanding the flow profile and geomechanical setting to decide on an optimal flow condition for the wells. An innovative solution-driven approach was identified with production logging playing a key role. Based on the geomechanical model, calculated fracture gradient indicated higher stress in the shallower section and lower stress in deeper intervals. Multistage fracturing was performed. Post fracturing, production logging was carried out in Well A at two different chokes to understand flow behavior in wellbore and correlate with reservoir response. Based on these results, an intermediate choke was selected for production logging in Well B to observe any improvement in flow behavior. An integrated study of geomechanics, fracture performance and production logging resulted in deciding an optimal flow condition for the wells. Results are presented for a two well operation. Production logging results indicated that deeper intervals were producing higher compared to shallower layers, thereby validating the geomechanical model. Also, fissures were encountered during deep stage fractures, indicating potentially high production from reservoir from these stages due to better flow conduit. This was also confirmed from the production logging results. In Well N1, production logging data, in the lower choke, indicated sluggish and unstable flow behavior with the top three stages underperforming. However, at higher choke, a steady and uniform flow was observed. The production logging results were also observed to be in line with the obtained frac-operation parameters on the higher choke. However, an anomaly was observed in the second stage of Well N1, which is estimated to be as a result of fractures closing down due to higher stresses in shallower depths. Based on this, an intermediate choke was selected to flow Well N2 and record production log data to observe and evaluate the flow behavior at a different choke. The flow was still observed to be sluggish and unstable at the intermediate choke. Hence, a final decision was taken based on all the different conclusions to flow the wells at higher choke to maintain optimal frac stage performance and a uniform and steady flow. Rare geomechanical setting of reservoirs presented challenges in accurately characterizing them. The paper recognizes the versatility of the production logging tool in delivering and understanding both reservoir response and wellbore flow conditions. The integration of fracture response with production logging results enabled validation of the reservoir response and provided valuable insights into understanding the flow behavior inside the well, and finally optimizing well productivity.

During the exploration design phase of recent pre-salt development in Santos Basin, it was identified great potential for the production of some wells, generating great expectation by how it would perform in the production phase, above the average of 30,000 bpd. The Subsea and Topside design were developed based on this expectation and therefore, diameters were limited considering the premises of 45,000 bpd production from the well to the FPSO. As a result of first oil production the expectation not only became a reality but also was largely supersede, confirming a very high production potential of up to 65,000 bpd per well, some of which are at the world top list of highest production wells for deep and ultra-deep waters. Despite the outstanding high potential of the well, full production was then, not able to be achieved due to limitations considered in the design's premises of 45,000 bpd per well, what overcome the already great expectation. In this scenario, there was intense effort to make the real production potential of the wells viable. To fit the design to the new dynamic flow conditions, a multidisciplinary technical assessment team was mobilized involving several disciplines such as: Subsea Equipment, Wells, Risers, Process, Piping, Instrumentation and Automation, in addition to Operational Safety, a non-negotiable value. After technical discussions between those different disciplines, alternative proposals were raised that could make possible a safe operation under this new challenging condition. The defined actions were implemented and currently the wells already operate on high levels of production. On the FPSO with those high production wells, due to this individual increase in the production, whose potentials exceed by 45% the design capacity, generating a significant increase in the profitability of the asset, contributing to revenues anticipation in the company's cash flow. This article presents the piping and instrumentation study to deal with a high flow velocity issue. The methodology adopted to overcome the challenges in vibration and erosion considered an unusual design approach, leading to some field test to check the effectiveness of the solution. This alternative approach allowed this increment in production rate per well piping branch.

Paraffin buildup is a fact of life in many oil and gas production fields. When downhole reservoirs lose pressure or temperature, paraffin precipitates and builds up on everything from pipe to valves to instrumentation to the walls in vessels. This buildup slows the process, constricts lines, and clogs instruments. Chemical treatments to keep paraffin from precipitating out of the fluid are widely known, but expensive. In addition to treating the liquid, producers should also consider treating the devices in the flow line to resist buildup. This paper will show how using nano-material to treat surfaces of components in the flow line—such as sensitive instruments, vessels, meters, valves—can slow or stop the buildup of these contaminants. By changing the bonding energy of the surface metal, these nano surface treatments hinder the ability of contaminants to adhere to a surface. These treatments do not affect mechanical, optical, or electrical properties of the treated devices. The discussion will include technical differences between a "coating" and "surface treatment" and the impact of these differences on a flow process. The paper will highlight environments that are best suited for these nano surface treatments and the different application methods available for treating devices. Data will showcase the performance of nano surface treatments in common applications, such as Coriolis meters, turbine meters, valves, flow and level devices. Producers have seen significant extension in the functional life of these devices and achieved significant operational savings. The paper will discuss how this data applies to other applications such as vessels, chemical reactors, filters, and more. In conclusion, nano-materials offer new and novel ways to maintain flow through valves, sensitive instruments, and other critical components in a flow line. Surface treatments, using nano-materials are easily applied, have a permanent effect on the surface energy of the metal, and do not hinder the optical, mechanical, or electrical properties of treated devices. Benefits of these treatments include reduced maintenance downtime and cost, improved performance of critical instrumentation and increased reliability of flow meters and valves.

Multiple leaks in production tubing of deep wells can be efficiently identified using fiber-optic distributed temperature measurement and thereby mitigating the health, safety and environment (HSE) risk associated with a potential well barrier failure. Further, a production log can be used to gain more insight and finalize a way ahead to resolve the issues of the well integrity. An innovative solution-driven approach was identified with fiber-optic distributed measurement playing a key role. Multiple leaks were suspected in the production system and a fiber-optic cable was run to identify possible areas of leak path. In these deep wells, after the fiber-optic data acquisition, a production log was recorded across selective depths to provide more insights on leak paths. Post identification of leak depths, a definitive decision between tubular patching and production system overhaul was decided based on combined outputs of fiber-optic, production log and tubular patch technology. Results are presented for a two-well operation. Taking an example of Well A, leaks were successfully identified at three depths using the novel operational approach. Further, operation time was reduced from three days (conventional production log measurement performed during daylight operation) to one day (combination of fiber-optic distributed temperature sensing and production log in a single run). Diagnosis of production system issues were completed in one flowing and one shut-in survey condition, thereby reducing the risk of HSE exposure with multiple flowing conditions (conventional production log measurement). Additional insight and confirmation on leaks were observed from production log data which helped identify the presence of a leak across the tubing body. This observation was substantial in deciding whether to proceed with tubing patch or replace the entire production tubing. Tubing patch technology was not satisfactorily recognized to provide well integrity across leak depths. Hence, the decision was made to replace the entire production tubing. The novel operational approach affirms the versatility of fiber-optic distributed temperature measurement in solving critical issues of operation time and reducing HSE exposure while delivering decisive information on production system issues. The paper serves as a staging area for other applications of similar nature to unlock even wider horizons for distributed temperature sensing.

Assessment of coating performance under flowing condition by using a proprietary flow loop system has been established. The 2 3/8" flow loop was designed to maintain a flow rate of 0.03-0.04 m 3 /sec, pressure of 3300kPa and temperature of 150°C to simulate actual field condition. Test section consisting of two 35" straight tubes with 45° elbow was internally coated and connected to the flow loop which was run continuously for 14 days with deionized water under the specified test condition. Upon completion, visual inspection, EIS and linear abrasion test were done on the test section to evaluate the coating integrity post exposure. Small blisters were noted at the elbow section potentially due to the improper surface preparation and/or higher fluid velocity at the bend section. Impedance value of 10 7 Ω/cm 2 is a magnitude higher than the acceptance limit of 10 6 Ω/cm 2 while abrasion resistance was found less than the set limit of <100mg/1000 cycles. The flow loop test has been shown to be a reliable tool to evaluate the effect of wall shear stress and fluid erosion on internal tubular coating.

The consequences of sand production are often disadvantageous to the short and long-term productivity of the well. Although some wells routinely experience controllable sand production, these are the exception rather than the rule. Sand production and its management over the life of the well is not an attractive situation but is often essential to extract the resource. Knowing the root cause behind sand inflow in a well and the possible results can inform an appropriate strategy to safely extract as much of the resource as possible. The sands in such reservoir units often have high permeability and are mechanically weak and prone to sand production. The producing wells are often completed with gravel-packed completions for efficient sand control. Most of the wells have multi-zone completions for better productivity but this further complicates reservoir characterization. This paper describes the first use of downhole sand impact detection technology in such fields. The sand detection technology integrates the fully digitized high-resolution acquisition with signal processing and interpretation algorithm to enhance the sand particle detections as small as 0.1 mm in diameter and up to 1,500 impacts per second. The tool is designed to immune the sensors from any background noise and gas/liquid jetting effect. A combination of production logging tools (PLT) and the sand impact detection tool, was used to understand four phase zonal contributions (gas, oil, water and sand) and pinpoint sand entry in these cases. Results exceeded expectations and the ability for the sand detection tool to accurately detect the point of sand entry enabled immediate intervention to eliminate sand production in these case studies. One of them also resulted in increased production of 7.4kb/d oil without any sand flow and with greatly reduced gas-oil ratio as compared to pre-intervention production. The work clearly demonstrates the practical and effective use of downhole sand impact detection with new sand detection technology to identify and isolate sand production in wells. The innovative tool design makes it feasible to detect even small sand particles in adverse wellbore conditions and varied production rates, thus adding a detection of the fourth phase in an otherwise three phase production log.

A reservoir with a rare geomechanical setting of higher stresses at shallower depths and vice versa was fractured. The multistage fracture responses were validated using production logging data. Further, production optimization was achieved by understanding the flow profile and geomechanical setting to decide on an optimal flow condition for the wells. An innovative solution-driven approach was identified with production logging playing a key role. Based on the geomechanical model, calculated fracture gradient indicated higher stress in the shallower section and lower stress in deeper intervals. Multistage fracturing was performed. Post fracturing, production logging was carried out in Well A at two different chokes to understand flow behavior in wellbore and correlate with reservoir response. Based on these results, an intermediate choke was selected for production logging in Well B to observe any improvement in flow behavior. An integrated study of geomechanics, fracture performance and production logging resulted in deciding an optimal flow condition for the wells. Results are presented for a two well operation. Production logging results indicated that deeper intervals were producing higher compared to shallower layers, thereby validating the geomechanical model. Also, fissures were encountered during deep stage fractures, indicating potentially high production from reservoir from these stages due to better flow conduit. This was also confirmed from the production logging results. In Well N1, production logging data, in the lower choke, indicated sluggish and unstable flow behavior with the top three stages underperforming. However, at higher choke, a steady and uniform flow was observed. The production logging results were also observed to be in line with the obtained frac-operation parameters on the higher choke. However, an anomaly was observed in the second stage of Well N1, which is estimated to be as a result of fractures closing down due to higher stresses in shallower depths. Based on this, an intermediate choke was selected to flow Well N2 and record production log data to observe and evaluate the flow behavior at a different choke. The flow was still observed to be sluggish and unstable at the intermediate choke. Hence, a final decision was taken based on all the different conclusions to flow the wells at higher choke to maintain optimal frac stage performance and a uniform and steady flow. Rare geomechanical setting of reservoirs presented challenges in accurately characterizing them. The paper recognizes the versatility of the production logging tool in delivering and understanding both reservoir response and wellbore flow conditions. The integration of fracture response with production logging results enabled validation of the reservoir response and provided valuable insights into understanding the flow behavior inside the well, and finally optimizing well productivity.

During the exploration design phase of recent pre-salt development in Santos Basin, it was identified great potential for the production of some wells, generating great expectation by how it would perform in the production phase, above the average of 30,000 bpd. The Subsea and Topside design were developed based on this expectation and therefore, diameters were limited considering the premises of 45,000 bpd production from the well to the FPSO. As a result of first oil production the expectation not only became a reality but also was largely supersede, confirming a very high production potential of up to 65,000 bpd per well, some of which are at the world top list of highest production wells for deep and ultra-deep waters. Despite the outstanding high potential of the well, full production was then, not able to be achieved due to limitations considered in the design's premises of 45,000 bpd per well, what overcome the already great expectation. In this scenario, there was intense effort to make the real production potential of the wells viable. To fit the design to the new dynamic flow conditions, a multidisciplinary technical assessment team was mobilized involving several disciplines such as: Subsea Equipment, Wells, Risers, Process, Piping, Instrumentation and Automation, in addition to Operational Safety, a non-negotiable value. After technical discussions between those different disciplines, alternative proposals were raised that could make possible a safe operation under this new challenging condition. The defined actions were implemented and currently the wells already operate on high levels of production. On the FPSO with those high production wells, due to this individual increase in the production, whose potentials exceed by 45% the design capacity, generating a significant increase in the profitability of the asset, contributing to revenues anticipation in the company's cash flow. This article presents the piping and instrumentation study to deal with a high flow velocity issue. The methodology adopted to overcome the challenges in vibration and erosion considered an unusual design approach, leading to some field test to check the effectiveness of the solution. This alternative approach allowed this increment in production rate per well piping branch.

Well integrity to prevent catastrophic damage has always been a key focus of the Oil and Gas industry and Oil and Gas operators keep working to reinforce it. Today, well integrity data available throughout the life of the well remains limited. Being able to know the wellbore parameters at different depths would help operators anticipate and identify problems throughout the life of their well. In addition, knowing the exact performances of each pipe will provide operators with the actual safety margin they have against well load cases, therefore allowing them to better monitor the well, based on real well data. The integration of a pressure and temperature sensor element in tubulars is possible thanks to the use of MEMS (Microelectromechanical systems) technology. Low-power consumption combined with an adapted transmission technology opens the door to the use of this intelligent technology inside an O&G well. Embedded sensors allow operators to access previously inaccessible well areas in real time. The qualification of this technology is carried out in a way as to ensure the integrity of the system and its long-term viability. This paper will present an innovative intelligent tube solution, from its qualification to its deployment. This solution will change the way wells are monitored. By combining the data retrieved by the sensors with the actual resistance of each pipe in the well, operators will be able to adjust their production parameters while ensuring the safety of their installation. This approach is new and, leveraging the latest IoT technologies, opens a new era for easier and optimized data-based Oil and Gas well monitoring.

The use of conventional process simulators is commonplace for system design and is growing in use for online monitoring and optimization applications. While these simulators are extremely useful, additional value can be extracted by combining simulator predictions with field inputs from measurement devices such as flowmeters, pressure and temperature sensors. The statistical nature of inputs (e.g., measurement uncertainty) are typically not considered in the forward calculations performed by the simulators and so may lead to erroneous results if the actual raw measurement is in error or biased. A complementary modeling methodology is proposed to identify and correct measurement and process errors as an integral part of a robust simulation practice. The studied approach ensures best quality data for direct use in the process models and simulators for operations and process surveillance. From a design perspective, this approach also makes it possible to evaluate the impact of uncertainty of measured and unmeasured variables on CAPEX spend and optimize instrument / meter design. In this work, an extended statistical approach to process simulation is examined using Data Validation and Reconciliation, (DVR). The DVR methodology is compared to conventional non-statistical, deterministic process simulators. A key difference is that DVR uses any measured variable (inlet, outlet, or in between measurements), including its uncertainty, in the modelled process as an input, where only inlet measurement values are used by traditional simulators to estimate the values of all other measured and unmeasured variables. A walk through the DVR calculations and applications is done using several comparative case studies of a typical surface process facility. Examples are the simulation of commingled multistage oil and gas separation process, the validation of separators flowmeters and fluids samples, and the quantification of unmeasured variables along with their uncertainties. The studies demonstrate the added value from using redundancy from all available measurements in a process model based on the DVR method. Single points and data streaming field cases highlight the dependency and complementing roles of traditional simulators, and data validation provided by the DVR methodology; it is shown how robust measurement management strategies can be developed based on DVR’s effective surveillance capabilities. Moreover, the cases demonstrate how DVR-based capex and opex improvements are derived from effective hardware selection using cost versus measurement precision trade-offs, soft measurements substitutes, and from condition-based maintenance strategies.

In a deep water well completed with coil tubing gas lift (CTGL), significant threat on flow assurance issues has been identified due to the Joule-Thompson effect generated from the high differential pressure of the supplied gas at 3400psi with the required pressure in the well which is below 1500psi. Several wells which have low liquid rate flowing colder with the CTGL due to the Joule Thompson-effect elevated the risk of hydrate formation. Monitoring of Wellhead Temperature (WHT) alone can be a challenge since WHT is below ambient and indication of WHT increase can be interpreted as either as an increase in liquid rate or well quit flowing. The paper describes operator experience in developing an effective flow assurance scheme for prevention and treatment should the well experience hydrate related plugging and devises a strategy for contingencies and remedial actions to reactivate wells effectively without significant production deferment. A holistic approach to manage flow assurance issues in below ambient WHT deep-water dry tree wells completed with CTGL was designed, undertaken, and proven effective. Thorough investigation to analyze the root cause of the blockages along the production tubing was conducted. Several intervention options were considered with very limited clearance for the type of intervention can be conducted in the wells of concern. Decision was made to proceed with the bull-heading method via the CTGL as it was found to be the most cost efficient and quick solution. Preventive measures were then taken to avoid similar future events from happening. Three deep-water dry tree wells which was completed with CTGL were experiencing blockages in the production tubing during an unplanned shutdown. The total potential of these wells amounts to 2600bopd and warranted the team to investigate a quick solution before attempting a workover which is costly and requires longer duration for planning before execution. Two out of the three wells treated with exothermic chemical injection were successful and restored 2000bopd production. Pre-qualification testing demonstrated similar trends of pressure communication between CTGL and tubing head pressure (THP) on the successful well treatment. Chemical solution which produced heat by exothermic reaction was bullheaded into the well with immediate communication established after injection. A standard operating procedure was then developed to manage the wells under this category and prevent future blockage. Culmination of the unique approach for wells with slim tubing (CTGL) to resolve a problem should be looked at from various angles. Investigation must be conducted until the flow restriction root-cause has been identified. Preventive measures then can be taken to avoid similar occurrence which will minimize value leakages and economic impact to the field. De-risking via conducting pre-qualification and Design of Experiment based on scenarios prior to arriving at solution helps to increase chances of successful treatment.

Slug flow in multiphase flowlines can cause operational instabilities which, when severe, lead to mechanical damage or even shutdown of processing facilities. While a number of control schemes to handle slugging have been published, many of them require subsea instrumentation or make use of calculated "pseudo-variables" for control, values which have no real physical meaning. Hydrodynamic slugging was anticipated during design of a new facility in Angola, and a simulation study demonstrated that a control scheme from the published literature could be applied effectively to control the slugging. However, that solution was rejected because of the use of a pseudo-variable as the principal control point. Therefore, a novel control scheme was developed and tested on simulation for both hydrodynamic slugging and severe riser-induced slugging and later patented. ( 1 , 2 ) The project implemented the novel active slugging control using a topsides control valve and topsides instrumentation. While a pseudo-variable, a pseudo-flow controller, was employed, it was part of a cascade scheme such that the principal control variable was a real topside pressure measurement. Upon commissioning, slugging at the facility was found to be more severe than anticipated during design, but the novel active slug control scheme was effective in controlling incoming slugs.

Discovered in 1964, the Beta Field in the Niger Delta sedimentary basin consists of 25 stacked hydrocarbon-bearing reservoirs located between 5,500 and 12,000 feet true vertical depth subsea (TVDSS). A total of 26 wells have been drilled in the field, of which 11 are presently on production. Oil production peaked at 8,900 stock-tank barrels per day shortly after field start-up and has been on the decline. More than 40 years since production start-up, the Beta Field remains a relatively immature, distinctly underdeveloped asset. Only about 59 million stock tank barrel (STB), or 8% of its estimated stock-tank oil initially in place of 740 million STB, had been produced by the end of 2017. Two horizontal wells were planned in the field to provide additional drainage points and increase field production. However, a production forecast of the planned wells showed potential early water breakthrough and high water cut because of unfavorable mobility ratios of a slightly viscous oil and proximity to oil/water contact (OWC). To mitigate the production challenges and improve the reservoir sweep, autonomous inflow control devices (AICDs) were selected to be installed on the sandface completion. These wells were drilled and completed during the COVID-19 pandemic, bringing additional challenges in equipment availability and logistics with potential to derail the successful completion of these wells within the required timeline. An innovative retrofit screen design, leveraging detailed engineering design and remote collaboration, enabled the conversion of ICD sand control screens to cyclonic AICD screens. AICD nozzle placement was optimized using a reservoir-centric workflow that integrates the full reservoir model with the sandface completion. Real-time interpretation of the data enabled computation of porosity-permeability and saturation estimates from logging-while-drilling (LWD) logs, which was then used in updating the reservoir model in near-real time. Using a segmented well modeling approach and a refined flow distribution from heel to toe, AICD nozzle placement was optimized in real time utilizing LWD measurements from open hole along the horizontal drain, aiding the design and configuration of the AICDs. The Beta-7 and Beta-8 wells were successfully drilled, completed, and put on production. The horizontal drains were landed within 5 to 10 feet of the top of the reservoir, maintaining at least 20-ft distance from the OWC. The forecasted simulation showed possible water influx from the toe of the horizontal as opposed to the heel because of existing water leg and high permeability at the toe. This was supported by high water-cut production from that zone in the nearby wells. This insight from the full-field simulation model enabled an informed decision on the AICD design.

Planar laser induced fluorescence (PLIF) is a measurement technique that can be used to provide a laboratory reference for validating the performance of field instrumentation that either directly measures mixture density or infers it from a combination of ancillary techniques. PLIF density measurements offer high-speed response and the ability to resolve minute flow features in transient flow patterns. Fundamentally, PLIF can also be used to verify multiphase flow models and predictive tools that are used for designing production piping. The use of PLIF to determine an instantaneous mixture density of two-phase flows has been successfully accomplished in previous fundamental laboratory studies found in literature. However, the use of this technique to determine the mixture density of three-phase flows for field-related scenarios has not been previously evaluated. To assess PLIF as a potential reference measurement system, a testing effort was undertaken to measure the instantaneous mixture density from a comingled oil-gas, water-oil, and oil-water-gas flow that was subjected to slug, churn, and bubble transient flow conditions inside of vertical piping. The objective of this work was to compare and validate the results obtained using the PLIF measurement approach against a commercially available gamma densitometer and tomography system for a variety of flowing conditions. The PLIF technique was able to resolve transient flow features and density values for both two-phase and three-phase flows through the piping. Distinct slug flow features such as the slug head, gas pocket, pocket collapse, and the tail were captured by PLIF and were observable in the raw image sequence captured by a high-speed camera. Additionally, the results for a variety of water-oil-gas flowing conditions were within 3% difference of a mixture density model that was calculated from liquid and gas flow measurements utilized in the test facility. The comparison of the PLIF results to the reference instrumentation indicates that this technique is successful at obtaining a mixture density for steady and transient oil, water, and gas comingled flows.

Non-thru bore drilling tools often feature limited flow range capabilities due to their design complexity. An ever-growing demand in high flow rates required a new technical solution that has the lowest possible pressure drop across the tool. Potential erosion issues as well as consistent functionality of the tool were key design requirements. A new friction reduction technology is presented that addresses the applications with flow rates ranging from low to high. Initial computational fluid dynamics (CFD) analysis suggested the flow split can be executed by restriction at the tail end of the power section. This, however, was challenged by the first test run that took place at 550gpm (5¼-in. tool outside diameter [OD]). While the run objectives were met in its entirety, upon tear down, the early signs of erosion were noticed on the valve assembly. With this evidence on hand, a critical design change was implemented, and as a result, the restriction was moved down the power section to spare the vortex at its tail end. Further improvement was retrofitted to protect the restriction itself with a simple addition of a sleeve. Further field runs were executed with the new tool setup. As the run count progressed, the newly redesigned technology achieved the objectives by delivering effective friction reduction at consistent frequency and pressure drop. It soon became evident that the step change in flow rate did not affect the tool wear and tear. Since its inception the tool has set two field records. The first commercial run marked the fastest curve in the county. As this technology rises to prominence in the US and international markets, more operators are experiencing the savings and lower Authorization For Expenditure (AFEs). The novelty of the design presented in this paper is in the drilling engineer's ability to design and construct wells with increased complexity (high dog leg severity [DLS], directional difficulty index [DDI], extended reach, and multi-lateral) where friction reduction technologies are critical to achieving run objectives. This technology fills a technical gap by meeting the new standards of high torque and flow rates in a compact and robust design. At the time of this writing, no other friction reduction technology meets these tool specifications.

Unique structures are formed when gases and liquids flow simultaneously in pipelines. The geometric characteristics of these structures are fundamental parameters in intermittent flow regimes. The length of liquid slugs and Taylor bubbles are inputs to mechanistic and empirical models for pressure drop estimation, slug catcher sizing and determination of the periods of no or low liquid in pipelines. Although slug flow has been studied for decades, there still exists a lack of comprehensive understanding of flow structures dynamics due to the complex interactions between the gas and liquid phases in two-phase flow. This study investigates the influence of pipe inclination on the length and hydrodynamics of large gas structures in intermittent flows, particularly, ‘Taylor bubbles’ in slug flow regime. An experimental study was conducted in a 67 mm ID pipe to estimate the bubble lengths of an air-silicone oil mixture from void fraction measurement using a twin-plane Electrical Capacitance Tomography (ECT) tool. The results show that the pipe inclination, gas and liquid flow rates have a substantial effect on the length of large bubbles in slug flow. Taylor bubbles get longer when the void fraction increases, or the pipe inclination deviates towards the horizontal pipe orientation. The influence of pipe inclination on bubble length is quite significant; this variation in bubble length with pipe inclination is attributed to the expansion or compression of large gas structures when there is an alteration on the forces acting on the bubble nose. The weight of the liquid column above the bubble nose which has been often neglected in earlier models was identified to have a notable effect on the volume occupied by the large bubbles and consequently, its length. A semi-mechanistic model is proposed based on the analysis of forces acting on the Taylor bubble nose in a quiescence liquid phase. A comparative analysis of the model and previous models shows that the proposed model outperforms existing mechanistic and empirical models across all pipe inclinations. This study gives an insight into the effect of pipe inclination on the length of large bubbles during slugging in pipes, as these bubbles can be up to 10 times longer in horizontal pipes compared to vertical pipes at the same flow conditions. The proposed model has the potential of estimating the length of large bubbles across all pipe inclinations in upward slug flow with acceptable accuracy, particularly for pipelines installed in undulating terrains.