Distributed temperature (DTS) and distributed acoustic (DAS) fibre optic sensing are now commonly used as key reservoir surveillance tools. This work shows the benefit of continuous downhole monitoring during the lifetime of a well. Fibre optic cables were permanently installed in a doublet injector/monitor well system as part of a CO 2 controlled released experiment at the In-Situ Laboratory in Western Australia. During the completion and injection operations various planned and unplanned events (mud circulation, cementing, drilling, wireline logging, gas and water flows) occurred. The events were monitored from surface to reservoir with DTS and DAS fibre optic cables. The DTS was recorded continuously data starting during well completion throughout the lifetime of the wells while DAS was recorded at specific points in time, mostly associated with borehole time-lapse seismic acquisitions. For the well completion stage, the interpretation of the DTS dataset acquired during mud circulation provided information about thief zones above the reservoir. During cementing and cement hydration, DTS highlighted areas of large breakouts and confirmed cement in-fill in those intervals. During the drilling of an unexpected cement infill, it provided a unique insight into downhole progression of the drill bit. During the CO 2 injection stage, DTS enabled monitoring the phase behaviour at the injector using distributed temperature data combined with a permanent pressure downhole gauge. At the monitoring well, the injected gas breakthrough was clearly detected at reservoir level within 1.5 day after the start of injection. Moreover, the accumulation of the CO 2 over time was captured accurately at reservoir level for a further 3 days. During an unexpected leak in the casing, gas from the reservoir started entering the monitoring well leading to cyclic release of water and gas at the surface. The DAS dataset enabled to pin-point the exact moment the casing leak occurred while the DTS dataset captured the cyclic nature of water and gas leakage. The sensitivity of the tools and interpretation methods are such that the downhole location of the event can be determined within 1 m and the timing within a few seconds. More importantly, the continuous and distributed recording allowed monitoring the events developing in time over the full length of the well. This work highlights the unique benefit of permanent distributed monitoring using distributed fibre optic sensing during the lifetime of a well. The continuous and distributed recording allowed monitoring events developing in time over the full length of the well and provides direct observations for the different events while providing near-real-time information about downhole processes.

Quantitative information regarding multiphase flow of oil, gas & water in wells or pipelines are very important in continuous well performance monitoring, production optimization, flow assurance, well testing, production allocation, etc. So far, the multiphase flow measurement methods are usually of low efficiency, low accuracy, high cost and delay delivery, and hard to reflect the real transient fluid production performance at wellheads or pipelines. Therefore, it is urgent to seek accurate and reliable multiphase flow detection devices and methods that can meet the monitoring demands of unconventional oil and gas resources. Breaking through the technical bottleneck, a novel method and device for online multiphase flow detection based on magnetic resonance (MR) is proposed. The flowing MR data acquisition, processing and interpretation methods are proposed to fill the blank of traditional methods. The full bore, straight tube design does not restrict the flow line and eliminates wear of internal parts and pressure drops, the Halbach magnet structure is designed to provide a uniform magnetic field inside the bore while cancelling the magnetic field outside the housing of the device, the separate antenna structure is designed to eliminate flow effects on MR measurement, and the integration of measurement and control technology realizes unmanned operation. With the good indoor experiment and field application results, it has achieved accurate, reliable, green, in-situ and online detection of multiphase flow. As a flowmeter, the device reduces the amount of measuring equipment needed and manages wells more efficiently. And as a ‘fluid analysis laboratory’, it can provide first-hand information on oil and gas properties. It also marks another new application direction of MR technology in the petroleum industry after well logging.

Oil and gas companies operating carbonate oil and gas condensate fields in Kazakhstan have been carrying out acid stimulation activities leading to a substantial increase in hydrocarbon production. Nearly all treatments were considered a success. Nevertheless, a certain level of optimization in the production enhancement methods that could, potentially, have brought additional technical and financial benefits, were overlooked due to various reasons. A comprehensive review of historical treatments on several fields located in West-Kazakhstan region was performed to identify areas to improve post-stimulation well performance. This review identified improvements including "cleaner" fluid selection, optimised design and treatment schedules. Historical treatments in the oil field typically used straight hydrochloric acid as the main acid, polymer-gelled (self-diverting) acid as the chemical diverter, and linear guar gel for displacement, and diagnostic tests. The application of a modern single-phase retarded acid to replace the straight hydrochloric acid was identified as a key improvement that would yield more efficient wormhole generation and an improved stimulation ratio. Another opportunity for improvement was to upgrade the chemical diversion system from polymer-based self-diverting acid to a viscoelastic surfactant-based (polymer-free) diverting acid system. The use of an oil-based displacement fluid with high retained permeability instead of linear gel and to reduce the hydrostatic pressure post-acidizing, thereby improving flowback, was also employed. Extended core flow testing for regained permeability and solubility were carried out with several acid systems to compare their capabilities and efficiency to create conductive wormholes, and their dissolution capacities. Additionally, emulsion, and sludging tendency upon contact with wellbore tubulars and formation crude was checked to verify the acids’ compatibility with hydrocarbons produced from the target reservoir. After the prerequisite laboratory testing, field trials commenced applying various combinations of fluid technologies in high-rate matrix stimulation treatments. The optimizations resulted in higher (normalized) post-stimulation productivity index (PI), facilitated formation cleanup, and enabled more efficient operations. A similar approach is, currently, being implemented in other stimulation projects in the region, and the results are being replicated. As has been mentioned above, one of the main enhancements implemented as part of this work is the employment of the single-phase retarded acid. Most of the published literature discussing application of the acid covers the cases of stimulation of relatively hot reservoirs (BHST>100°C) as acidizing of high-temperature carbonate rock using traditional hydrochloric acid is a great challenge. The current paper provides details of the case studies, where the acid system was successfully implemented in combination with several other stimulation technologies for mid-temperature ranges. One of the objectives was also to assess whether application of reduced volumes of the retarded and diverting acids would still lead to improved wells’ productivity. Positive results of the laboratory studies, treatment modeling, and field trials were validated by the increasing normalized post-stimulation PI with each optimization step.

This paper elucidates the key flow assurance challenges for China’s first National Deepwater gas field development in South China Sea and the facilities design forming the overall flow assurance management strategy. The discussion covers early stage feasibility studies through current stage of project execution. In addition, the finding of flow assurance analysis serves as key input for start-up and commissioning guidelines as well as operating procedures. The development consists of a semi-submersible, with the Eastern and the Western loops spanning more than 40 km of Subsea Production System (SPS). Due to long subsea tiebacks, integrated flow assurance analysis is rolled out to ensure comprehensive risks analysis and active risks management. In particular, key challenges associated with typical Deepwater characteristics such as high pressure and low temperature are actively managed. With design water depth of more than 1500 m and more than 10 Deepwater subsea production wells, robust flow assurance management strategy is required from early activities such as well unloading, well test, pre-commissioning, first gas, through late life decommissioning. Integrated approach is implemented for overall system thermohydraulics analysis, which is used as basis for key flow assurance assessments, including but not limited to management strategy for hydrate, scales, erosion, and slugging. Detailed management strategy and philosophy are discussed in the main body of this paper. Overall chemical management strategy, for instance, is fully optimized to reduce Health, Safety, Security and Environment (HSSE) impact, coupled with sufficient safety margin to ensure minimum downtime. Through integrated flow assurance analysis, all key risks are identified and actively managed. This shows the importance of integrated flow assurance approach to ensure overall project safety and integrity. More importantly, overall optimization can be successful rolled out when the field is in production. This serves as a positive lesson learned for future Deepwater development in South China Sea.

The Dvalin gas field is located in the Norwegian sea on NCS and is operated by Wintershall DEA Norge. It is supported by two independent reservoir structures, Dvalin East and Dvalin West. The field was explored through wells 14S and 15S in 2010 and 2012, respectively. The field is characterized by dry gas, high CO2, high temperature (160 °C) and high pressure (SIWHP 620 bar). The targeted Garn sandstone has good reservoir quality, but with a high permeability contrast. The field development was sanctioned in 2016 and calls for a 4 well solution through a centrally located subsea template, producing gas back to the host platform Heidrun TLP 15 km away. Water depth at location is 380 m and targeted reservoirs are at 4140 m MSL (East) and 4240 m MSL (West). Production plateau rates are estimated to be approximately 106 MMscf/D (3 million std m 3 /d) per well where thin high-permeability zones within the Garn formation are expected to dominate the inflow. The lateral facies development is thought to be relatively homogenous throughout the field, thus S-shape wells falling off to vertical through the reservoir will ensure effective drainage. Sand failure is expected after short time of production and would increase the risk of erosion causing severe damage to well jewelry and production facilities. It has been decided to integrate sand screens as a means of downhole sand control as part of the primary lower completion design. The sand screens will offer sand control, erosion resistance, hot spotting resistance as well as robustness towards a full hole collapse during reservoir pressure depletion. As the subsea completions are carried out from a mobile drilling unit in harsh environments, protection of the sand control filter media during installation is of utmost importance. This paper will describe the selection process of sand control and qualification steps carried out to use ceramic screens as the stand-alone screen solution for successful deployment and integrity for the Dvalin field development

As part of the reservoir monitoring effort in Field X (Offshore East Malaysia), five oil producers were deployed with double-ended fiber optics cable across reservoir sections and permanent downhole gauges (PDG). Each well has between 2 to 4 zones. This has enabled various distributed temperature sensing (DTS) benefits such as gas-lift monitoring, well integrity, zonal-inflow profiling, and stimulation job evaluation, etc. This paper demonstrates and discusses the approach of incorporating both DTS & PDG data in Well B-1 to intrepret temperature signatures andanomalies during recent tubing-integrity tests, matrix acidizing and post-job production performance. Well B-1 is a gas lifted well that consists of three zones, and its production has been declining over years due to potential formation damage during drilling and fines migration issue. Hence, Well B-1 has been selected for matrix acidizing treatment to enhance the productivity. Prior to execution of the acidizing job, several conformance jobs such as tubing-integrity tests, injectivity test, and tubing pickling were performed. A baseline temperature was acquired to assist in the evaluation. Due to operational challenges, the DTS data transmission wasn't acquired in real-time. However, each event's temperature profile has been studied thoroughly against the actual event schedule. Some significant findings are i) completion accessories effect (feedthrough packers) creates temperature anomalies, and ii) several leak points detected mainly between two upper zones where there was significant cooling effect due to injected fluid. The first-stage main treatment was conducted focusing on Zone 3. Due to leak points between the two upper zones, Zone 3 didn't get the designated main treatment volume. Second-stage main treatment, Zone 1 & 2 were treated together due to time constraint unlike Zone 3. Post job production temperature profiles showed significant changes in the flowing temperature slope compared to pre-treament profile where there is an increase in overall wellbore temperature indicating increase in liquid volume and Zone 2 indicating higher Joule-Thompson cooling effect (more gas production).

In this case study, high resolution temperature array data, acquired during a Drill Stem Test (DST), were able to identify and quantify flow behind the liner. Quantifying the flow rate behind the liner between the production zones was of significant value to the operator to reduce the uncertainty in the Pressure Transient Analysis (PTA). The high resolution temperature array was deployed clamped to the outside of the Tubing Conveyed Perforating (TCP) guns, which were used to selectively perforate multiple zones. Using wireless acoustic technology the temperature data were transmitted to surface to enable real time feedback during the DST. A novel thermal heat exchange model was built that could take advantage of the high resolution temperature array data acquired during the entire test. The results of the model were compared to the real data to validate the results and provide accurate flow rate measurements of the flow behind the liner in real time during the test. A sensitivity study on the various model input parameters was also carried out to reduce the uncertainty in the thermal model, the results of which are detailed within the paper. Being able to quantify the flow behind the liner allowed the operator to adjust their PTA results and provided a more robust reservoir model. Typical thermal models in the industry are unable to quantify flow behind the liner in this environment. A new thermal model had to be developed that could take into account the complex heat transfer processes and take advantage of the high resolution thermal array data acquired during the DST. Despite the challenging wellbore environment during the test, the high resolution temperature data were used to provide a robust zonal flow confirmation and rate allocation during the flow periods. Whilst Distributed Temperature Systems (DTS) are gaining popularity in the oil and gas industry, typically the current technology does not provide the high resolution required to be able to quantify flow behind the casing. This new model, when combined with high resolution thermal array data, has wide ranging applications not only during the DST but also in long term completions where monitoring well integrity is a real industry challenge.

The first hydraulic-jet-fracturing multizone completion application was performed in an offshore high-permeability oil well located in the Bozhong oil field in Bohai Bay, China. A detailed case study is presented, highlighting operational challenges and lessons learned from the offshore multizone completion in the Bozhong field. Most offshore high-permeability oilwell completions in the Bozhong field employ tubing conveyed perforation (TCP) followed by frac-packing as multi-zone completions, which is practical in this field. Unlike conventional multizone frac-pack completions, to run perforation guns, the perforating must be completed first, followed by running isolation packers to complete the multizone frac-packing treatments. For hydraulic-jet-fracturing multizone completions, the hydraulic jetting tools are delivered to the target depth using drill pipe; following that, slurry fluid is pumped through the drill pipe to cut through the casing to create fluid flowing channels, which communicate with the pay zone formation. Lastly, the fracturing operation is completed by pumping both proppant slurry through the drill pipe and cleaning fluid through the annulus simultaneously, which creates dynamic hydraulic diversion as functions of isolation between zones. After completing one treatment zone, the tools are pulled to the next target depth, repeating the procedures, until the entire well is complete. After the fracturing treatment, the operator runs production tubing and other accessories, putting the well into production as usual. A detailed completion design and step-by-step operational procedures were prepared based on well data and work conditions to help ensure the effectiveness and safety of the offshore operation. Although some challenges were encountered during the operation, it was overall successfully performed, and significant performance improvement was achieved. After being in production for months, the candidate well has maintained a longer high-production-rate period than the offset wells completed using conventional multizone frac-pack completions. This hydraulic-jet-fracturing multizone completion has proven successful in the Bozhong oil field. The experiences and lessons learned can help benefit future multizone completion optimization for other similar offshore high-permeability oil wells.

The fiber-optic distributed temperatrue sensor (DTS) has been used for flow profiling in horizontal multi-stage fractured wells, and there were some reservoir/wellbore coupled thermal models presented by researchers. Although current theoretical models are developed for some certain application scenarios, the industry have realized the great potential of DTS for production prediction in unconventional resources. This paper presents a DTS flow profiling case for a horizontal multi-stage fractured well in tight gas reservoirs with open-hole packer completion scenarios by applying a newly improved theoretical model. In this paper, we started with the conventional semi-analytical wellbore-fracture-reservoir coupled flow/thermal model which have been developed for cased, perforated, and multi-stage fractured wells, and revised it to consider the special feature of openhole packer completion scenario. Since the formation fluid firstly flows through the fracture into the open-hole annular space between formation and the packer liner, then flow along the annular space until meet the frac port on the production pipe, we add a simulation sub-region representing open-hole annular which helps to understand the flow and heat transfer inside it. The presented model successfully simulated the two-fold flow regime caused by the simultaneous flow and heat transmission in the annular space and the production pipe. In each stage, the DTS temperature data possibly show double drops due to Joule-Thompson cooling effects at the fracture and frac port locations if they are not consistent. With the improved mathematical model, DTS monitoring data during a three-rate production test in a horizontal multi-stage fractured well in Erdos Basin of China was simulated and analyzed. The improved model with open-hole packer completion was applied and then the gas rate prediction was accomplished.

As the oil and gas industry enters the digital era, openness is a key enabler to realizing the vision of transforming the industry for the better. The practice of reservoir engineering and reservoir simulation is no exception. In this paper, an openness mechanism in a reservoir simulator using Python scripting language is introduced. It empowers engineers to utilize simulation in new ways. It extends simulator capabilities and enables people to implement flexible-control logic to solve field management challenges. The new openness mechanism in the simulator allows engineers to program and include Python scripts in a simulation model. These scripts interrogate and interact with the simulator. The scripts are executed by the simulator while running the model. Flexibility is available to execute the scripts at every Newton iteration, before and after every simulation timestep, at specified times, or when a criterion is met. Simulation model properties can be queried through the scripts, such as well connections, well properties, group properties, grid region properties, network entities, current simulation time, etc. The scripts can set properties such as well constraints, well and connection productivity index (PI), group production target, pausing or stopping the run, etc. Customized control logic, if not directly available in the simulator, can be implemented in the scripts that interrogate and drive the simulator. Such customization can be packaged as Python libraries and shared with team members, enabling continuous value creation. Public Python libraries, such as NumPy, pandas and pywin32 or win32com, can also be loaded in the scripts to extend even further what the simulator can do. The openness mechanism is demonstrated on case examples. They include customized action to acidize wells when production drops, approximating the geomechanical effect of decreasing well pressure, modeling the effect of fines in injected water on well injectivity, and connecting to a network simulator. Examples are also given on customized reporting for model diagnostics and result interpretation, setting production constraints based on economics calculated in an Excel sheet with complex fiscal regime, advanced gas accounting, management of sulphur content, dual-optimization to meet gas demand while honoring oil treatment capacity, and integrated asset modeling from reservoir to surface networks to processing facilities. the ability to extend built-in functionalities of a reservoir simulator and customize field management controls using user scripting language. It embraces innovation and enables continuous value creation in reservoir simulation.

Online pipeline management systems provide real-time and look-ahead functionality for production networks. However, they are limited by a dearth of data to inform their predictions. This represents a barrier to a true, high-fidelity ‘digital twin’ where greater integration with new sensor technologies is needed to bound model predictions and improve their reliability. In this work, we present a novel MEG (Mono-ethylene glycol) sensing system from OneSubsea, the AquaWatcher v2.0, and validate it in our newly-constructed HyJump flowloop. The HyJump flowloop has a unique subsea jumper-like geometry, with three low points and two high points and is equipped with a MEG sensor - mounted on the second low point. The sensor features an open-ended microwave frequency probe mounted flush to the pipe wall which measures the apparent permittivities of the liquid phases in the vicinity of the probe tip. It can determine the MEG concentration or water salinity by processing the measured permittivities, and has further shown that it may be able to detect hydrate deposition. Experimental work was performed to test the performance of this novel equipment while enabling a more accurate calculation of the overall mass balance in the flowloop. An experimental campaign was conducted where, in each measurement, the jumper low points were loaded with aqueous solutions of MEG at mass fractions between 10 and 30 wt%. The entire loop was then pressurized with Perth city natural gas to 1200 psi. The pipe wall temperature was controlled with a cooling jacket in the range of 25.2 °F to 35.6 °F. These conditions simulate transient shut-down and restart operations with a high probability of hydrate formation. Results illustrate that the MEG content readings measured by the sensor were consistently accurate within a 5% relative deviation with respect to the nominal values. Further, flow restrictions due to hydrate deposition were assessed in their severity through differential pressure measurements, where it was observed that the measured MEG content oscillates significantly during hydrate sloughing-type events. The HyJump flowloop facility offers a unique testbed for new subsea sensors, enabling performance evaluations with internal fluids at subsea conditions. The deployment of these novel sensors in the field will both improve the performance of integrated pipeline management solutions and assist operators in optimizing MEG injection dosages to enable higher fidelity hydrate management in subsea pipelines.

Water-oil emulsion formation is commonly observed at wellhead chokes and topsides control valves, with the impact mitigated by chemical injection. The presence of emulsions downhole in Pyrenees wells was inferred from their significant production rate impact and confirmed by the uplift observed from downhole chemical injection. The Pyrenees fields are located in the Exmouth sub-basin offshore Western Australia. Through analogy between individual Inflow Control Device (ICD) orifice elements and wellhead chokes, ICDs were suspected as the source. This paper describes experimental confirmation of emulsion formation by orifice type inflow control devices in Pyrenees field horizontal well completions and proceeds to characterise the emulsions formed. A purpose built flow rig combined Pyrenees crude oil and produced water under low shear, simulating reservoir flow conditions, before flowing through an orifice element at rates equal to peak and mid-life production. With liquid flow rate held constant, water cut was increased in 10% steps from 0 to 100% water content. A key component of the experimental system is a benchtop Nuclear Magnetic Resonance spectrometer equipped for non-invasive Pulsed Field Gradient measurement of the Droplet Size Distribution of the emulsions formed. Droplet size distribution is a fundamental fluid property that significantly impacts emulsion rheology. The heavy end component of the crude oil was characterised by a novel Enhanced Saturate Aromatic Resin and Asphaltene analysis procedure to facilitate benchmarking of Pyrenees with emulsion formation tendencies of other producing assets. This quantitative demonstration of emulsion formation by orifice type ICDs at near reservoir conditions is novel, as is observation of partial emulsification, and represents initial steps towards generalisation of models for emulsion formation and their transport properties.

Wax deposition during pipeline transportation of crude oil is one of the serious flow assurance problems faced in the petroleum industry ( Deka et al., 2020b ) and wax gelation phenomenon is an inherent characteristic of the wax deposition process and it must be investigated to understand the deposition process. Wax-gelation formation was simulated during flow of waxy oils by numerically simulating its gelling behavior during transportation under different operating conditions by developing a computational fluid dynamics (CFD) model. The modelling technique and the obtained results from this work would help to predict the wax deposition and gel formation tendency in different waxy oils. Wax deposition phenomenon was modelled for a model wax-oil mixture (representing a waxy oil). A numerical model was developed to predict the wax gelation with time and length of pipeline. It involves heat and mass transfer calculations and molecular diffusion mechanism is considered as the primary mechanism for wax deposition, with the calculations being performed for 5 days. The CFD model uses enthalpy porosity technique where wax-oil gel is treated as the solid-liquid region with porosity equal to the liquid fraction. Fluid flow was considered laminar with flow rates being 1-5 GPM and ambient temperature was maintained at 281.3 K. The developed numerical model predicts that the wax gelation increases with time initially and then slowed down subsequently and less increment is observed upon 5 days of fluid flow. These results indicate the wax gelation is fast initially and slows down subsequently, showing strong dependence on time. Wall temperature of wax-oil mixture and the gel deposit decreases from bulk fluid temperature (295.2 K) to the ambient temperature (281.3 K). Increase in the temperature difference between wall and ambient temperature leads to higher wax deposition and gelling formation. Wax gelation was observed to be function of time. The CFD model numerically-simulates the wax-oil gelling formation in terms of liquid fraction (gel formation), where the liquid fraction gets reduced up to 44.7 % upon crude oil flow in the pipeline, being highest at the centre and lowest at pipe-walls, indicating the possible gel formation regions on pipewall. The gel formation was strongly affected by the wall temperatures, duration and length. This work would be one of its kind to report CFD-simulations of wax-oil gel formation in pipelines, where interdependency of fluid flow parameters would be assessed. Therefore, in this work, an attempt was made to simulate the gelling behaviour of the wax crystals in pipeline using an enthalpy porosity technique which has been not been tested much before. Computational fluid dynamics is used in this work to simulate the wax-gelling phenomenon and the wax gelation is observed through observing the changes in the liquid fractions of the wax-oil mixture used in this work. The current work would provide a comprehensive understanding about the wax deposition and gelling phenomenon in waxy oils and would help to design waxy-oil pipelines with appropriate measures, especially in subsea conditions.

To control and equalize the horizontal well drawdown, Autonomous Inflow Control Device (AICD) are planned to be installed along the homogenous reservoirs in five infill wells at B field, Sarawak offshore (Malaysia). The very low viscosity contrast between oil and water (0.6cp and 0.5cp) with 37API degree at B gives unfavorable mobility ratio and water flows with a higher velocity than the oil. This paper presents the interdisciplinary approach to completion design needs which evaluated the efficiency and performance between conventional completions compared with passive inflow control device (ICD), AICD namely Rate Control Production (RCP) and Fluidic Diode to qualify the representative technologies for use at B fields. The very purpose of this flow control device is the extension of well life due to deferment of water and/or gas production prior to water and/or gas breakthrough occurs. Flow performance tests are used to measure the performance of these various flow control devices at representative downhole conditions. The comparative analysis was primarily based on elapsed time comparisons for water/oil ratio (WOR), gas/oil ratio and water cut and sensitivity to historical drawdown, productivity index and production cumulative performance. To reduce formation damage and screen plugging effect in these horizontal section, appropriate fluid conditioning, fluid displacement, filter cake breaker system and compatibility between screen and the fluid in which the bottom hole assembly (BHA) will be deployed are discussed in this paper. The gas-water-control completion using AICD technology is predicted to provide significant benefit during the field development with incremental oil recovery around 10-40%, allowing well production with low water and gas production.

A state-of-the-art time-domain electromagnetic tool is presented that is capable of quantifying four barriers individually, and inspecting a fifth barrier qualitatively. The working physics and salient features of the tool and its underlying technology are described. The new tool uses time-domain electromagnetic (TEM) or pulsed eddy current (PEC) technology, which has set the benchmark for individual quantitative tubular corrosion evaluation in multi-annular well systems (multiple concentric tubulars) in recent years. Time-domain electromagnetic tools widely used in the industry are currently capable of quantifying the individual metal thickness/loss in up to three barriers. The new tool employs three highly sensitive sensors to provide high-resolution analysis of the inner barrier, while providing sufficient radial depth of investigation for up to five barriers. The above features and advantages of the new tool are supported by modeling and fixture test results. Additional modeling is shown to compare and contrast the resolution and radial depth of investigation of the three sensors. Case studies from actual wells are also presented that illustrate how three sensors enhance the performance of this technology. Corrosion evaluation of multi-barrier systems is a major component of well integrity management because it can provide timely and cost-effective information for planning well repairs if needed. The ability of the new tool to inspect more barriers is important because it gives the operator better information for more proactive well integrity management. The novelty of the tool is in its ability to exploit the information-rich wideband pulsed excitation using three sensors that enhance the sensitivity to multiple barriers.

In coal-bed methane (CBM) horizontal wells, coal particles generally deposit on the low side of the wellbore to form a particle bed, which increases well pressure loss and even blocks the well. The coal particle bed undergoes changes in height and geometry with the fluctuation of gas and water production. Besides, with a low water flow rate, the water layer in CBM well is extremely thin. Both the dynamically changing particle bed and thin water layer make the conventional gas/water interfacial friction factor ( f i ) prediction method for stratified flow in horizontal pipe not suitable for that of CBM well. Based on the large-size multiphase complex flow experimental equipment, a gas/liquid/solid three- phase flow experiment in horizontal pipe was carried out. In the experiment, gas flow rate, water flow rate and coal particle size were the three main factors considered. During the experiment, the gas/water flow pattern, migration of coal particles and evolution of blocked section could be investigated through the transparent pipe. Furthermore, due to the significant effect of coal particle bed on the height of gas-water interface, a non-negligible gravitational pressure drop calculated using water level differences is taken into consideration when obtaining the friction pressure drop. In the experiment, three gas/water flow patterns including slug flow, stratified smooth flow and stratified wavy flow were observed. The coal particles mainly transport by means of rolling and saltating in the thin water layer under stratified flow and migrate by way of dispersing in water under slug flow. Besides, for particles no larger than 20-30 mesh, the blocked section tended to be overall driven forward like fluid by local high differential pressure and then led to the discontinuity of coal particle bed. However, for blocked section with particles not less than 10-20 mesh, instead of being driven forward, the coal particles on the top surface of it would be carried away layer by layer until the raised part was eroded off. Furthermore, as with the situation in gas/liquid two-phase stratified flow in horizontal pipe, f i in the experiment increases with liquid Reynolds number (Re L ). However, it is much larger than that of gas/liquid stratified flow under the same Re L ,. The analysis of experimental data presents a closely negative correlation between f i and the equivalent diameter of effective flow channel. As for the coal particle size, it has some indirect effects on f i through the equivalent diameter of effective flow channel. This work is helpful for coal particle management and productivity prediction during CBM development, which may provide guidance to particle-bailing operation and also serve as a basis for theoretical mechanistic models to predict the gas/liquid interfacial friction factor of gas/liquid/solid three-phase stratified flow.

Over the last few years, the oil and gas industry had observed a rapid increase in deployment of fiber optic sensing for downhole monitoring. In Field B, 7 wells have been permanently completed with Distributed Temperature Sensing (DTS) fibers that extend through the reservoirs section 2009 and 2015 respectively. After more than 40 years of production history, this was the first permanent installation of fiber-optic in SX Region. Undeniably the DTS provides a new surveillance experience for Field B; multiple conventional monitoring system can be replaced with permanent fiber monitoring while also effectively minimize production deferments. This paper presents the real-life challenges of fiber optic applications in Field B, offshore Malaysia. DTS wells are located in satellite platforms which are not accessible on daily basis. While the focus is always on downhole monitoring deliverables, a large proportion of upfront deployment is to invest on the surface equipment that can be complex and costly for data acquisition continuity. As such, biggest challenges faced by Field B are essentially surface-related. Challenges encountered post DTS fiber installations in Field B includes digital oil field set-up, surface hardware replacement and maintenance, local electric room (LER) power-supply stability, data transfer protocol, continuous streaming of DTS data from offshore to onshore, reduced data resolutions, software and capability development. Over the life of the well, these challenges possess significant cost impact and most of time are not captured during the project planning and development stages. In Field B, throughout 5 years post fiber-optics installation, multiple challenges have been overcome in order to maximize value of information from the downhole monitoring. Knowing that these challenges might impact the downhole monitoring deliverables, the plan for future permanent fiber optic installation in any asset should incorporate all the possible challenges with its mitigation plans identified and set in-place. The lesson-learnt highlighted are turned into future project best practices.

Surveillance of well work-overs and downhole operations is not trivial but is becoming increasingly feasible with recent improvements in the technology of fibre optics. Well cementing operations are critical for providing zonal isolation over the life of a well. However, there are limited downhole options to monitor and inform operations in real-time. Installing a permanent fibre optic cable enables surface to reservoir permanent surveillance. In this work, fibre optic cables were deployed in 4 different wells using different configurations and test passive and active distributed temperature sensing (DTS) setups to interpret the quality of the cement injection and hydration processes. Well cementing can occur during well installation and decommissioning. For 3 wells, fibre optic sensing cables were installed for the purpose of monitoring the casing cementing installation, detect zones of isolation and any background lateral flow in the formation. For one of the well, fibre optic cables were installed inside casing to monitor a full wellbore decommissioning cementing operation. Following the same process, datasets were acquired prior to and during cement injection. Dataset acquired during mud circulation highlights interval of thief zones and potential leakage zones for the cement into the formation. The real-time surveillance of cement injection informs about the top of cement but also the in-fill of breakout intervals and the blockage of thief zones. The long-term surveillance of the vertical temperature distribution enabled to determine the timing and intensity of the cement hydration process and provided a unique insight on the quality of the cementing operations and its possible correlation to breakout intervals and thief zones. Active DTS was also used to confirm the completion installation as temperature diffuses differently depending on the presence or absence of gravel pack and the thickness of the cement sheath. Our results show that downhole surveillance of cementing operations is possible using DTS. This technology enables high vertical accuracy in real-time and long-term surveillance providing insights on the quality of the cement bond. In this case study, DTS has proven to be a very valuable and reliable tool throughout the cementing operations at 4 wells.

This paper presents results from a flow test performed by TechnipFMC (TFMC) in December 2019 at the DNVGL Materials Laboratory in Oslo. A replica subsea multiphase meter (MPM) that includes a Venturi was used firstly to calibrate an Acoustic Sand Detector (ASD) for the X-mas Tree (XT) specific geometry, and secondly to monitor the impact of sand over the life of a typical high-rate subsea gas well. The replica subsea MPM body was built to mimic the subsea installation on a 5-inch TFMC Subsea 2.0 XT. Several sensors were then mounted on the test rig – including ASDs and Wall Thickness Monitors (WTM) on the MPM block. Phase 1 testing was conducted over a range of air velocities with various sand particle sizes and with water injection to assess ASD sensitivity. In Phase 2, high air velocity and simultaneously high sand loading were applied to evaluate the response of erosion monitoring sensors and the mechanical robustness of the system. It was shown that the sensitivity of the ASD mounted on the MPM block was satisfactory and that furthermore, standardized calibration curves can be generated, thereby allowing a more accurate measurement of the sand mass flow rate for the specific XT geometry. The capability of WTMs placed at the meter Venturi to monitor long-term erosion was also demonstrated. To our knowledge, such a complete flow test with sand has never been performed on a full-scale subsea MPM geometry. The knowledge produced has allowed the verification of the accuracy of CFD erosion models, ASD calibration and the potential for development of an Erosion Monitoring System (EMS) using inputs from a range of sensors integrated into a single ROV-retrievable XT mounted metering system.

When flow is initiated from a well, a physical shock front is created in the reservoir, beginning at the completion. This shock front moves out into the reservoir as a Mechanical Wave with constant intensity and with velocity decreasing vs. the square of the distance. This is known as infinite acting radial flow (aka ‘transient flow’) and is very well understood (at least at the producing well’s location). The capillary shockwave represents a moving boundary to the pressure decay field that forms around the well ( Hurst 1934 ). This active region of decay behind the moving shock front will adopt a near semi-steady state flow regime in the reservoir, as required by the second law of thermodynamics. This depletion region is composed of radial capillaries that produce flow to the well and create pressure or elastic depletion in the reservoir. The cone of influence or region of pressure depletion bounded by the shock front around the well is the active reservoir at any given time. Eventually, the capillary shockwave boundary condition at the radius of investigation will either encounter all of the reservoir boundaries, or will continue to grow into an aquifer. Energy is redistributed by a faster moving inertial wave that passes through the open capillaries. Each capillary has finite rupture strength due to the same initiating capillary pressure that produces the bounding shockwave ( Goldsberry 1998 , 2000 ). Hence the cone of influence can be recognized as a structure composed of radiating capillaries behind a moving boundary condition. Each capillary is considered an individual contributor to the flow to the well and each capillary has a contribution to flow that is in proportion to its volume ( Goldsberry 1998 ). When a capillary reaches a sealing boundary, it ceases to grow and contributes less to the flow of the well than the capillaries that are still growing. Since the well is generally controlled by a choke, the demand upon the cone of influence is constant. This creates an imbalance in the second law of thermodynamics. In order to reconcile this imbalance, the choke-well interaction then produces a secondary cone of influence bounded by its own capillary shockwave boundary condition. The goal of this paper is to describe the primary shockwave boundary condition and the inertial waves that produce pressure redistribution within the cone of influence. Traditionally, the inertial term is ignored in order to create a simplified diffusion equation model. It is not zero. Furthermore, in the classic diffusivity derivation ( Earlougher 1977 ), the capillary entry pressure is assumed to be small and hence neglected. It is also not zero. By excluding these terms in the classic derivation, the result is a simplified model that works for infinite acting radial flow at the producing well location, but does not match observation well data, nor producing well data after the first boundary is encountered. If both inertia and capillary entry/threshold pressure are included in the derivation for the diffusivity equation for transient flow, a model that is based upon a capillary structure emerges, which predicts (and matches real field data) a depletion region that grows predictably with time, with distinct boundary contacts and arrivals of primary and secondary shock fronts.