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In recent times, studies on slugging have focused on the development of new and optimal slug mitigation techniques. This study focused on investigating a new proposed severe slug mitigation technique which involves combining self-lift and gas-lift. The self-lift slug mitigation technique is a unique approach that involves in-situ gas being tapped-off via a by-pass pipe along a pipeline upstream of a riser. The in-situ gas is then re-injected into the riser column via an injection point on the riser, to break liquid slugs within the riser column and mitigate severe slugging. This study adopted a methodology which involved validating the field data by comparing field pressure data with OLGA simulation based on input data from the field. The field case involved a deepwater oil field, consisting of well X1 and well X2 comingled along a 2712m pipeline section and a 1513m riser section. The pipeline-riser system in consideration in the case-study experienced hydrodynamic slugging, during the early life of the field; when the two wells comingled on the pipeline-riser system were operating at 3000 bbl/d. The 3000 bbl/d scenario (well X1 – 8.745 kg/s and well X2 – 25.13 kg/s) was initially modelled via OLGA. Furthermore, the 3000 bbl/d scenario was modified by moderating the flow rates at well X1 to 3.25 kg/s and well X2 to 12.13 kg/s until severe slugging scenario was observed, which was verified via pressure and holdup trend plots. Self-lift technique alone was able to moderate holdup within the riser column, however pressure trend at the riser column was observed to be over 20 bara (290.075 psi) which is the design pressure for the inlets of the separator. Further analysis of results obtained via the combination of self-lift and gas-lift at 2 inches by-pass diameter and 8kg/s gas-lift showed that pressure at the riser column was stabilized to approximately 20 bara (290.075 psi). This study showed that a by-pass internal diameter to pipeline-riser internal diameter ratio of (1 : 2) or less is crucial to the effectiveness of self-lift and gas-lift slug mitigation techniques combined. The new approach proposed in this study also has the potential of moderating the high compressive cost associated with gas-lift in deepwater scenario.

Over the years, drillstring vibrations have become a major issue in the oil and gas industry. The search for energy has led operators to encounter various unconventional conditions such as high temperature, high pressure, etc. in their quest for oil and gas. Drillstring vibrations amongst other problems are regularly encountered in such conditions, leading to tool damage, increased downtime and other adverse problems. In this work, an analytical approach was adopted to investigate the major parameters that affect drillstring vibrations and a viable control method was recommended. The vibration models were analyzed and a modified model was developed to fit the standard drilling conditions, starting from the top of the drillstring down to the formation being drilled. Considering the Parameters which were often neglected in the works of this nature such as mud density and formation fracture pressure were investigated in order to understand the extent of their contributions to drillstring vibrations. Using standard drilling conditions for the simulations, we were able to identify the key parameters which significantly affected the vibration profiles. The data obtained from the simulations were used to obtain a markedly better profile which showed a marked reduction in amplitude. The analysis of the effect of all considered parameters to the vibration profile led to the conclusion that weight on bit / torque on bit and rotary speed are the key factors that affect drill-string vibrations and that the density of the drilling fluid used make little or no difference why formation fracture gradient caused a reduction in drillstring vibration as it increases.

Agbami is a prolific deep-water field which commenced production in 2008 and achieved peak production a year later, in 2009. Plateau production has been maintained in the field since 2009 through various efforts which include drilling of additional wells, pressure maintenance by gas and water injection, acid stimulation and choke/well-lineup optimizations. This paper focuses on the production optimization in the Agbami field obtained from choke and well-lineup optimizations. Agbami production system is an intelligent network that comprises of completions, wells, subsea flowlines and risers. Currently there are 24 wells, 8 subsea flowlines and 8 production risers in the production system. Multiple wells flow commingled in each riser, but each well can be lined-up to either of two risers in a riser loop. Parameters such as pressure, temperature etc. are monitored in real time at different nodes in the network. Production optimizations are achieved by manipulating the production control chokes at the completions, wells or risers; and/or by changing the line-up of the wells. Robust surveillance and monitoring are key to achieving successful production optimization. Periodic production tests are done at the completion, well and commingled riser level; while periodic pressure build-ups are done on the completion level. These surveillance data (plus real-time data) are used to update the completion, well and riser constraints and to calibrate the production network model. By continuously monitoring the operating constraints and comparing the constraints with the current production data, optimization opportunities are routinely identified. The identified opportunities are evaluated using the calibrated model and if viable, are proposed for execution. The key challenge is having good calibrated production network model to use for optimization. Choke and well lineup optimizations have proven to be an effective approach to obtaining increased production at no cost. These efforts have led to an average production gain of 12,000 BOPD per year in the past 8 years in Agbami field.

While the oil and gas sector is facing one of its most significant slumps, producers have moved their focus in optimizing production of their existing wells rather than drilling new wells. Artificial Lift Systems (ALS) have played a significant part in optimizing and enhancing the production of existing assets. The primary scope of ALS is to maximize productivity; however, there are many such systems applicable, the selection of the most suitable lift system plays a vital role in cost optimization of the well. A primary type of ALS is hydraulic lift, which has been recently applied successfully in north Iraq. A special form of hydraulic lift is the jet pump. This technology has proved to be one of the best lift types for the operator in the region, with the unique concept of no moving parts inside the downhole pump, which has dramatically reduced downtime and the need to move a workover rig to the well site. A jet pump can be installed in a well using a variety of techniques, depending upon the well completion and can be customized easily depending upon downhole conditions. However, if one does not monitor the operation and working parameters continuously, the performance of a jet pump will be reduced as well conditions change. A jet pump was optimized as a test project for a well which was not producing naturally. This study was based on a variety of operational conditions of the well, such as injection parameters, flow restrictions and paths, surface pumping unit power, nozzle throat combinations, vessel operating pressures, and the productivity of nearby wells to calculate the reservoir potential. The evaluation, analysis, and design of a jet pump for this well were carried out on Jet Pump Evaluation and Modeling Software (JEMS). The most suitable nozzle throat combination for this well was 10D, which was used successfully to lift production to approximately 2,000 bpd. This study describes the process and gives the results for successfully reviving production in a well with hydraulic lift. It also depicts the improvements of the optimized input power for each well depending upon the design selected. In the end, a methodology towards the selection of the best design and operating parameters of the jet pump for the mentioned well is discussed. The installation, types, and operation of the jet pump system are discussed in detail for a proper understanding of the lift method.

The exploration and production of oil and gas mostly occurs in remote locations, so as to minimize human exposure and Health Security Safety and Environment (HSSE) risks. Shell Companies in Nigeria is not any different having operated for over 50 years in Nigeria with the largest footprint of all the international oil and gas companies operating in the country spanning over land, swamp, shallow waters and offshore terrains. Shell Petroleum Development Company, the operator of a joint venture (the SPDC JV) between the government-owned Nigerian National Petroleum Corporation – NNPC (55% share), Shell (30%), Total E&P Nigeria Ltd (10%) and the ENI subsidiary Agip Oil Company Limited (5%) focuses mostly on onshore and shallow water oil and gas production in the Niger Delta with about 60+ producing oil and gas fields and a network of approximately 5,000 kilometers of oil and gas pipelines and flow lines spread across the Niger Delta. Escravos Beach is over 60km from the closest major city, Warri, a major oil and gas zone in the Niger Delta. It is bounded by the Escravos River to the East, Chevron canal to the North and the Atlantic Ocean to the South and is covered with predominantly mangrove forest especially along the creeks and consists of a number of natural and man-made waterways (rivers, creeks and canals). Unlike most other onshore operations, this location can only be accessed via the waterways; thus requiring the rig equipment and every other equipment to be channeled via the waterways and subsequently on land to arrive at the site. The amphibious nature of this operation requires a combination of onshore and swamp requirements with increased HSSE exposure, logistics requirement and cost. This paper aims to highlight the practical experience garnered in the rig move and workover operations of Rig XYZ which operated in the Escravos Beach region.

Managing sand production is becoming an increasingly important issue for petroleum production wells, particularly in challenging environments such as deep water, or gas fields with high flow rate production where sand tolerance is very low and changing the completion strategy could be costly. Sand production prediction is an integral part of overall field development planning. Consequently, it is important that the risk of sanding is accurately evaluated and appropriate measures are taken for well completion. The critical part in a sanding study is to define a proper rock deformation threshold based on laboratory tests or field observations. Due to the lack of sufficient field sanding data or for the sake of modelling simplicity, the rock deformation threshold is frequently defined either inappropriately or too simplistically because of the failure to recognize the intrinsic heterogeneities of reservoir rocks.In this paper, two cases are presented with the deformation threshold "critical plastic strain limit" defined by a numerical simulation approach. One case represents a weak to medium-strength sandstone reservoir and the other a stronger, clean sandstone reservoir. In both cases, a comprehensive core testing dataset and a field-validated geomechanical model are available. In the weak-medium strength case, there were also several years of production history with sanding observations available from a few wells.The numerical method uses an elasto-plastic material model where the rock behaviour is numerically defined from systematic triaxial compressive core tests and a rock failure criterion based on the plastic strain limits modelled from Advanced Thick-Walled Cylinder (ATWC) core tests with calibration against field sanding observations. From the modelling of a range of high-quality ATWC tests and field sand production experiences, strong correlations are found between the critical strain limit and the rock compressive strength for both cases indicating different critical strain limit thresholds for different rock strengths and rock types.Although high-porosity and weaker rocks may still have a higher risk of sand production than low-porosity and stronger rocks, the risk of sanding may not be as high as predicted if a single threshold is used for the entire rock strength and porosity range. The use of a single threshold for the whole field could over- or under- estimate the risk of sand production, especially for reservoirs with a moderate risk of sand production.Sanding evaluations of the two cases revealed that the predicted sanding risk is potentially misleading if a simple sanding threshold is defined without adequately capturing the heterogeneity in reservoir rocks. This approach may prohibit the selection of an appropriate completion strategy for the entire field. This paper is concluded by presenting a rock testing program procedure for sanding evaluation studies to better capture the heterogeneity in reservoir rocks and, hence, to predict the sanding risk more reliably.

The commercial Computational Fluid Dynamics (CFD) code STAR-CCM+ was used to simulate the dynamic behaviour of a tension leg platform in extreme weather conditions. The numerical results of surge motions and tendon tensions were compared against the measurements acquired in model tests. The full-scale CFD simulations were then conducted on the basis of the settings performed in modelscale simulations. Both model- and full-scale surge motions and tendon tensions predicted by CFD were in good agreement with the measurements. Using CFD results, it was revealed that the component of the vertical wave-in-deck force caused a slam force on the platform followed by tendon slack situations in the down-wave tendons.

Subsea cooling in oil and gas production might seem to be opposite to the usual flow assurance challenge, maintaining a high enough flowing temperature of the produced stream in order to ensure problem free transport of the crude from well to the host. During FEED and detailed design, particular focus is aimed at maintaining a required temperature with insulation and even electrical heating are employed in order to achieve this. Hydrate formation, wax and asphaltene deposits are challenges that are connected with too low temperature, and considerable effort is spent in quantifying acceptable temperature, and cool down times of subsea equipment. So one might ask why and where is the need for subsea cooling? It turns out that there are situations where the well fluids are very warm and reduction in the temperature is required for profitable development of a field. For example, where an expensive flow line material would render the installation too costly, a reduction in temperature might make the investment evaluations look attractive, or where heat is generated subsea by for instance a subsea gas compressor. The temperature greatly affects the corrosion rate, and by changing the temperature, chemical dosage can be optimized, which further strengthens the financial analysis of a field development. This paper focuses on active subsea coolers, i.e. subsea cooling systems that are equipped with adjustable means, and attempts to analyze and benchmark four different subsea cooler types using a generic wet gas production case. A recent development involving a sea current controlled active cooler is introduced and compared with three other active cooler types and how they operate with a given set of operation and turndown conditions are presented. A comparison of weight, size, auxillary equipment and required topside scope is also included.

This paper highlights the phenomenal achievement of a Malaysian operator's first fast track drilling operation in a deepwater well offshore Borneo. The collaborative well planning (CWP) method fundamental to the drilling success is discussed. The discussed drilling environment is an overpressured deepwater area that has not only forced the earlier A1 and A2 to early total depth (TD) and caused abandonment of geological targets, but also contributes to numerous operational problems. Despite the challenges, operations on A3 ST-1 required significantly less operational time cost than budgeted. The difference between the previous two wells and A3 ST-1 was that, during the planning period, multidisciplinary concerns were addressed more carefully in real-time by employing CWP to unite geoscientists, drilling engineers, and other stakeholders using 3D integrated platform technology. This CWP helped the operator meet objectives for A3 ST-1, a fast track well that required only two months of drilling time, rather than the typical 12 to 18 months. It resulted in one primary well location and six geological sidetrack scenarios being accomplished in only one day. Upon the end of the operation, Well A3 was drilled with one successful cased hole sidetrack to geological target objectives without significant operational problems. A significant portion of the success can be attributed to the proper accommodation of concerns and best practices of rig usage, engineering insights, tool usage, and geological conditions during the planning process through the common software platform that can seamlessly allow collaboration of both geoscience and engineering data. The process automation only requires key drilling parameters to construct well trajectories, which was also significant in terms of shortening the planning time. This paper describes the first application of the CWP concept in offshore Borneo, which has become a trendsetter in terms of efficient and safe deepwater drilling planning and operations.

An oil well located offshore Southeast Asia, was completed with a dual string and after 20 years of production the drawdown decreased significantly even with gas lift mandrels located in the long string, 480m (1575ft.) above the lowest producing zone. A deep gas lift (DGL) system was installed based on field data that indicated the production could be improved by increasing the drawdown to optimize the gas lift performance. One of the main limitations was the depth of the production packer for the gas injection production. The deep gas lift system was selected as it enables the gas injection point to be moved deeper into the well, which in turn results in the ability to create a greater drawdown. The lowermost gas lift mandrel was straddled with two packers and a crossflow assembly that provided dual flow paths in a single system as well as suspending 350m (1148ft.) of 1.5in coiled tubing (CT) that acted as the injection string to a predetermined depth. The operation was the first of its kind in which the DGL system was conveyed with a CT Catenary system on board a dynamically positioned vessel (DP2); this enabled flexibility in deployment of the long bottomhole assemblies in small offshore platforms without the presence of a crane. For this operation, modifications were required in the original CT equipment to maintain well integrity, providing double barriers at every step of the installation. The DGL system was successfully and safely installed in a live well in 3 days. After its installation, the production rate increased tremendously. Similar operations will benefit from understanding the rationale in the selection of the solution, the details of the installation with the CT catenary system, the barrier systems put in place during the open-hole installation, the depth correlation methods and the lessons learned.

The paper presents a new drilling technology. With the Electric Impulse Technology it is possible to drill boreholes with less energy demand, more drilling speed and less drill bit changes. Drilling results, calculations und further steps will be presented. The new technology uses high voltage impulses to destroy rock with almost no wearing of the drill bit. Engineering a drill bit with this technology will advance the drilling activity for oil and gas as well as geothermal drilling and mining. The objective is to develop a whole drilling system suitable for a conventional drilling rig. Within the first step an impulse voltage generator including a drill electrode was engineered, tested and evaluated. Drill performance under pressure with OBM was investigated. Next steps will include the developing of the energy supply for the system and field tests. The impulse voltage generator designed as a downhole tool was developed to drill bore holes with a diameter of 12 ¼ inch in hard rock with a drill speed of 1 to 2 m/h which is comparable to conventional drilling bits. Furthermore it withstands temperatures up to 200 °C and pressures of 1000 bar. The components of the generator have a lifetime about 350 h, so a bit could be used almost seven times longer than a conventional drilling bit. In laboratory tests a block of granite was drilled on a length of 50 cm with a diameter of 12 ¼ inch. Additionally further materials like limestone, sandstone, marble and iron ore were successfully destroyed. Pressure tests up to 500 bar with WBM and OBM were performed and analyzed. The whole design process of the generator and the electrodes was accompanied by network analysis and FEM calculation. The paper presents the new results of the development of a drill bit based on the Electric Impulse Technology. After the engineering of the impulse voltage generator and promising results the development of the power supply get into focus. The pressure tests show that the Electric Impulse Technology will work under borehole conditions. In addition to early processing the drill bit will be configured for drilling with WBM concerning environmental and financial issues.

Commissioning and start-up (CSU) of an all-subsea development of offshore gas reserves feeding into an onshore liquefied natural gas (LNG) plant is complex and challenging – yet project success is driven by a timely and flawless LNG project start-up. To this end, development wells in the Jansz-Io gas field had to be flowed back to the onshore facility to prove up Gorgon LNG Train 1 capacity before the wells could be relied upon for uninterrupted gas supply to Train 1 start-up. Here, a carefully-considered well proving sequence can yield unique, once-in-a-lifetime and zero-cost subsurface data that improves reservoir characterisation and future decision quality. This paper describes: Design aspects of the well proving sequence that enabled opportunistic pulse and interference tests to be conducted at no expense to Train 1 start-up: Optimality: balancing the well proving objectives of the various functional stakeholders (flow assurance, facilities, operations and subsurface) while honouring all CSU / operational constraints. Flexibility: recognising and planning for CSU uncertainties (subsea gathering system versus onshore plant readiness; onshore gas demand; and pigging schedule for liquids management). Contingencies: planning for sequence execution issues such as well unavailability and gauge failure(s). Execution – how the tests were executed and how the reservoir responded. Analysis and interpretation of pulse and interference test data, whereby: A simple, conceptual analytical model based on the line source solution was constructed and used to guide analyses in more detailed numerical models. A single-layer 2D numerical reservoir model with local grid refinement at the wells was constructed and used to infer inter-well average reservoir storativity (porosity-total compressibility-thickness product, ϕcth) and transmissivity (mobility-thickness product, kh/μ) and across-fault communication. Existing 3D models were calibrated to the pulse and interference testing data for improved reservoir performance predictions in support of future reservoir management decisions.

SRA is one of the well platforms in a marginal gas field operated by PT Pertamina Hulu Energi Offshore North West Java (PHE ONWJ). SRA production is evacuated to the SA platform via a 6.3 km 8" Main Gas Line (MGL), which has been in operation since 2002. Changing corrosiveness of the fluids produced at SRA after the MGL integrity and in 2015 several leaks were detected. Repair by conventional means or replacement was deemed uneconomic. A study was therefore initiated to evaluate the technical and economic feasibility of low capital cost and low maintenance cost technologies to rehabilitate pipelines in marginal fields with high CO2 content without increasing safety or environmental risks. In the appraisal stage, several technology options were considered and a thermoplastic pipe was selected as the preferred alternative compared to traditional rigid carbon steel pipeline. The assessment process started with a pipeline technology review, followed by technical compatibility/acceptance study, a check of commercially available pipe sizes and a comparison of total installation cost, installation schedule, and operation-maintenance considerations. The decision was facilitated by Expected Value Decision Analysis. The expected value of each option included CAPEX, OPEX, NPV, and all quantified aspects and risk. The thermoplastic plastic pipe assessed is a flexible pipe for shallow water consisting of polyethylene (PE) internal liner, annular ring steel strip armor, and PE outer sheat. The PE inner liner is nearly hermetic, but allows traces of gases such as CH4, CO2, H2S, and H2O to permeate through. These permeants tend to accumulate in the flexible pipe annulus. A slight overpressure above atmospheric develops in the pipe annulus driving the gases to the end fittings where they are vented, preventing excessive pressure build up. Additional weight is required for on bottom stability of thermoplastic pipe to be laid in Offshore North-West Java area. The installation spread will be using the available Pipe Lay Barge blanket contract for the Pipeline Repair and Replacement Program.. Even though some advantages of flexible pipe cannot be obtained in this project, such as additional weight required and lay barge usage instead of DP2, the selected concept is still the most economic compared to other options. The CAPEX is 10% less than carbon steel pipe. OPEX reductions can be achieved by reducing pigging operations and eliminating In-line Inspection (ILI) and chemical injection.

This article deals with developing production mode of gas lift operation of production wells. A method for solving the issues associated with immediate assessment of the potential flow rate of a large number of wells, as well as for the search of candidates for wellwork is presented. A method for solving optimization problems that arise in operation of gas lift wells on offshore is proposed. Examples of using the proposed method at offshore oil fields of the Socialist Republic of Vietnam that are operated by JV Vietsovpetro are shown.

AKAC participated in the full scale ice trials of the newly built R/V Sikuliaq, owned by the National Science Foundation and operated by the University of Alaska-Fairbanks. The purpose of the trials was to identify its ability to conduct science missions in ice, as well as to develop operational procedures for conducting independent science missions in ice. This paper gives an overview of the key design features of the R/V Sikuliaq that enable it to conduct science missions in ice, as well as the observations and results from the full scale trials. This paper provides real life experience on the operational performance of a state of the art research vessel. The experiences shared in this paper are applicable to a wide range of operations in ice, including station keeping in ice and towing in ice.

Extreme values for local ice pressure are a primary consideration in the design of local structure for ships and offshore structures in arctic environments. ISO 19906 (2010) includes guidelines for a probabilistic approach in determining the local design pressure for Arctic offshore structures. However, the standard is vague in how it should be used. The probabilistic method employed in the standard is the event maximum method developed by Jordaan et al. (1993). It accounts for the expected exposure of the local structure to ice pressure and includes a constant, a, used to describe the relationship between local pressure and area. The constant a is derived in Jordaan et al. (1993) and extended in Jordaan et al. (1997) and reported in Taylor et al. (2010). The a-area relationship is based on the local pressure values from the very aggressive multi-year ridge rams of the CANMAR Kigoriak trial (1982). This leads to a very conservative a-area relationship and may be excessive for some ice conditions. This paper includes an explaination of the use of the event maximum method in ISO 19906. Local pressure data obtained through shear strain gauge systems from Polar Sea (1983) and Oden (1991) have been reanalyzed using the event maximum method (Jordaan et al. 1993, 1997). The data has been sorted by both ice thickness and ice concentration to investigate the existence of a trend between ice thickness and local pressure.

The current practice for protecting wellheads and associated subsea facilities from icebergs on the Grand Banks is an Excavated Drill Centre (EDC), which is simply an excavation in the seabed in which wellheads and associated facilities are placed. Free-floating icebergs simply drift over an EDC, with the exception of those that roll as they pass over an EDC and increase draft sufficiently to enter. The risk from gouging icebergs entering an EDC is a function of the clearance between the surrounding undisturbed seabed and the top of the facilities in the EDC, and the distribution of gouging iceberg keel penetration depths. A field program conducted in Bonavista Bay in 2015 was used to estimate iceberg rolling rates, and an analysis of high resolution iceberg profile data collected in 2012 was used to determine the associated distribution of iceberg draft changes that occur due to rolling, and thus the rate at which iceberg keels penetrate an EDC due to rolling events. Modeled iceberg grounding rates and iceberg scour data from the Jeanne d’Arc were used to estimate the rate at which gouging icebergs enter EDCs. Iceberg gouge data from the Jeanne d’Arc and a dynamic time-step iceberg simulation using the 2012 iceberg profile data were used to determine the impact rate for facilities in the EDC as a function of the distance between the midline and the top of the facilities (clearance). The analysis addresses some of the conservatisms in the current approach, allowing for reduced EDC excavation depths.

Turret-Moored FPSOs are frequently used for deepwater developments worldwide, with consideration of disconnectable turrets for harsh environment applications. This trend makes the interaction between the FPSO hull, mooring system, and riser systems a vital design parameter for arctic conditions. This paper provides a review of the various riser systems that can be considered for turret-moored FPSOs. These include proven coupled and decoupled systems (flexibles, Steel Catenary Risers, Steel Lazy Wave Risers, and hybrid decoupled riser systems), and also new riser concepts (e.g. the TCR - Tethered Catenary Riser, or the TSLWR - Tethered Steel Lazy Wave Riser). These systems are described in terms of design and functionality. These riser systems are discussed with consideration of the particular challenges of disconnectable turret-moored FPSOs and specificities of arctic conditions.

Exploitation of the Arctic's resources requires the mastery of the risks caused by extreme ice conditions. The design of offshore structures subjected to extreme ice conditions is a challenge for engineers since there are very few advanced design tools available on the market, especially those able to cope with the large variety of ice interaction and failure mechanisms. Different approaches have been used to model and study ice behavior. Among them are analytical, numerical and empirical approaches with different models being considered. Each model has its own advantages and drawbacks and is only generally dedicated to certain circumstances. In 2012 Technip, Cervval and Bureau Veritas initiated a common development program to offer a new tool for the design of offshore structures interacting with ice (Septseault, 2014, 2015) combining a variety of approaches and models. After three years, the first version of the Ice-MAS software (www.ice-mas.com) is now available. It simulates the ice loadings on a structure and the dynamic behavior of the drifting ice-sheet and floes around. Thanks to multi-agent technology, it is possible to combine in a common framework multiple phenomena from various natures and heterogeneous scales (drag, friction, ice-sheet bending failure, local crushing, rubble stack up) (Le Yaouanq, 2015). This work has been the subject of numerous validations, particularly by comparison with ice basin and in-situ results (Dudal, 2015). The Ice-MAS development program continues in 2016 with the addition of a capability to model the interaction of icebergs with offshore structures. This paper will introduce the co-simulation architecture proposed to simulate the complex interaction between an iceberg and a platform structure. It will focus on the hydrodynamic behavior of the platform and the iceberg including its stability. It will also consider the interaction between both bodies; including the non-linearity of the mooring system (in the case of a floating platform) and the local fracture mechanisms of the iceberg. The objective is to propose a new more accurate design method that will improve the overall ice management system for a project.

The purpose of this study is to investigate subsea pipeline leaks and their impact on the surroundings. A numerical approach using a computational fluid dynamics (CFD) package is used. The subsea condition is extremely harsh due to the remoteness and inaccessibility. Marine pipeline can be damaged directly by contact with drifting sea ice. Trenched pipeline is at risk as well, as it may be damaged by corrosion, or the pipeline could be plastically deformed by the resulting seabed shake down event. Furthermore, due to the remoteness and harsh climate of the under the ocean, it is difficult to conduct normal maintenance procedures. Leakage of pipelines in arctic subsea environment can have severe consequences. Leak detection and location identification in a timely manner is crucial because of the economic impact of a hydrocarbon spill to its stakeholders can be huge. Pipeline leakage could have an adverse impact on life, the environment, the economy and corporate reputation. It is imperative to take additional precautions while operating in the subsea regions, so rapid leak detection and location identification is crucially important. In this paper, a numerical modeling of a subsea pipeline leakage is performed using a 3-D turbulent flow model in computational fluid dynamics (CFD). Four different types of fluids are tested in this study, with specified operating conditions. It is difficult to conduct small-scale experiments on subsea pipeline with leakage, mainly because; the pipeline may need to release hydrocarbons to the environment. Further, since the industrial full-scale pipeline is large in diameter, fluid thermodynamics cannot be captured accurately in a small-scale, laboratory environment. Thus, a numerical simulation can provide a better understanding of pipeline internal flow and the consequences of pipeline leaks in different scales, reducing the cost and number of experiments. Commercially available ANSYS (FLUENT) computational fluid dynamics software is used to serve this purpose. ANSYS workbench provides integrated design, meshing technology, and large degree of freedom for pre- and post-processing for the fluid flow simulation in pipeline. The CFD simulation results in this study showed that the flow rate of the fluid escaping from the leak increases with pipeline operating pressure. The static pressure and pressure gradient along the axial length of the pipeline have observed a sharp signature variation near the leak orifice. This signature has been captured using pressure gradient curves. The temperature profiles near leak orifice indicate that the temperature is observed to increase slightly in the case of incompressible fluids; however, temperature drops rapidly for the compressible fluids. Transient simulation is performed to obtain the acoustic signature of the pipe near leak orifice. The power spectral density (PSD) signal is strong near the leak orifice and it dissipates as the distance and orientation from the leak orifice increase. The high-pressure fluid flow generates more noise than the low-pressure fluid flow. In order to model the turbulence large eddy simulation (LES) used and Ffowcs-Williams and Hawking (FW-H) model in FLUENT was activated to generate acoustic data. Time step of the simulation was selected At = 0.0005 s and the number of simulation 20000 to get higher frequency noise signal.

In 2015, LUKOIL-Nizhnevolzhskneft developed two intelligent multilateral (TAML 5) wells in the Korchagina field in the Caspian Sea—a first for LUKOIL and Schlumberger, the company's service provider. The development of offshore fields is difficult, requiring nonstandard procedures and solutions, including the use of new technologies to construct multilateral wells. This paper describes the approach to designing these wells with TAML 5 intelligent completions in conditions where there is a high risk of gas and water breakthrough. The main objectives for this type of completion were extending the production period before catastrophic gas breakthrough, increasing the drainage area by drilling several drains, and, as a result, increasing total oil recovery. The formation of Korchagina field is an oil rim with height of 20 m located between the massive (up to 90 m) gas cap and bottom edge water. In the majority of wells (usually extended-reach drilling (ERD) wells), the first three months of production see gas breakthrough, drops in oil production, and the gas/oil ratio (GOR) reaching values up to 5,000 m3/m3. To reduce the rate of gas breakthrough and delay water breakthrough, a new well design was proposed featuring the following technologies: dual-lateral production wells with a TAML 5 junction; active monitoring of inflows from each lateral in an interval of the junction by using multiposition valves hydraulically controlled from the surface; pressure and temperature sensor system that enables real-time tracking of the formation conditions in the drainage area of the laterals, estimates flow rate from each lateral, and interprets the obtained data to determine reservoir parameters. The first TAML 5 intelligent well had a very stable flow regime with a flow rate of more than 400 tons of oil per day. GOR and water cut showed a better dynamic when compared to offset wells in the field, where gas and water breakthrough was observed. One of the main reasons for this was the ability to control drawdown in each of the laterals by using multiposition valves installed in the pressure-tight junction. When compared to the standard monobore well drainage area, boundaries have been considerably extended. At the same time, production was achieved with much lower drawdowns than for wells with a single lateral, while maintaining the same flow rate. As a result of smaller reservoir and tubing pressure differences, the speed of the water and gas vertical movement significantly slowed down, even with the proximity of gas-oil contact (GOC) and oil-water contact (OWC) to the wellbores. The second TAML 5 well was sidetracked from the existing well. Prior to sidetracking, the well was producing with high GOR (more than 2,000 m3/m3) and low flow rate. After the sidetrack was drilled and completed, total GOR decreased by 75% while the production rate increased more than 3 times. The main reason for such a positive change was the increase in coverage ratio, as well as the redistribution of the drawdown between and along the laterals. In both wells, the intelligent completion enabled real-time drawdown redistribution to respond to changes in well production during the life of the well. The use of a pressure-tight TAML 5 junction is relevant for any field with an active gas cap. This manuscript provides the details of the development, justification, and field-testing of this new approach for the development of offshore fields by using multilateral intelligent wells and a pressure-tight TAML 5 junction to substantiate the advantages and benefits of this technology.

A communications company is installing a subsea fiber optics cable from Europe to Asia around North America through the Beaufort and Bering Seas. At various points along the main line branching units are installed to allow for branch legs to be laid to various villages along the coastline of Alaska. These branch legs will provide vital telecommunication service to remote communities and businesses. The villages include Nome, Kotzebue, Point Hope, Wainwright, Barrow and Oliktok Point (Purdhoe Bay). This paper will present the many problems and solutions associated with shore approaches in Arctic conditions.

With a series of physical model tests performed during February to August 2016, Arctic towing operation was investigated while towing a Gravity Base Structure (GBS) in managed sea ice with varying parameters: ice concentration, floe size, towing speed and towing configuration. The CONDRILL™ Arctic driller (Gravity Base Concrete structure) is a promising structural concept for extended exploration drilling operations in limited open water season and in harsh ice conditions. In the studies, the model-scale Arctic driller concept were constructed and tested in different paraffin-made model ice conditions. The tests, designed to shed light on both the physics and the practicalities of moving the GBS in varying ice conditions where towing force and structural stability, influenced by ice resistance are central for a successful platform design. The current model test is the first in a series where the results will be used as design input as well as subsequent marine operations employed for moving the platform in managed sea ice. This paper discusses initial assessments of towing force under varying ice conditions through physically modelling the most significant ice load contributor (i.e., the ice accumulation and clearing process). Based on the model tests, an optimum towing configuration, which involves no permanent ice jamming in all the tested ice conditions, was identified. In addition, it was found that for ice concentrations lower than 60%, the towing speed (or hydrodynamics) governs the towing resistance and the influence from ice floes are minor. However, while at high ice concentration (e.g., ≥70 - 75%), we are shifting from a hydrodynamics governed scenario into multibody dynamic interaction governed scenarios, in which, ice accumulation/clearing and internal friction resistance between the ice floes dominate the tow resistance. The study highlights the importance of an efficient ice clearing mechanism to release the pressure built-up in front of the structure and transport broken ice to the wake region of the structure, which results in lower resistance during towing. The studies reported in this paper contribute to the following items: 1) The multibody dynamic based physical modelling test would be the first of its kind to isolate this important physical process and to study it thoroughly without the influence from other physical processes such as sea ice fractures. 2) The test results are useful to validate currently available numerical simulation tools based on Discrete Element Method (DEM).

This article describes how to build an integrated model of two fields in order to optimize gas production. It also describes how to find an optimal gas production ratio between the two fields producing into a single collection point, and the basic details and system limitations in carrying out this type of work. The result will be a tool that allows solving optimization tasks.

Ice infested shallow waters of the North Caspian Sea imposes challenging tasks like ice pile up, fatigue due to ice-induced vibrations and ice impact loads, which strongly affect the structural integrity of offshore installations. This paper explores the potential application of a Minimal Facilities Platform or is also known as a Conductor Supported Wellhead Platform (CSWP) in the North Caspian Sea region and specifically focuses on the design optimization of the substructure due to ice loads. The CSWP has not been used in the cold climate regions before. The intention of this research is to prove feasibility of CSWP to withstand loads in the ice infested shallow waters. The substructure design was optimized by application of an ice resistant conical structure with specific inclination angle at the ice-structure interface. Usually conical structures reduce ice loads and ice induced vibrations. However, a fatigue capacity may be reduced due to geometrical discontinuity with the increase of inclination angle. This was shown in the design analysis.

Offshore oil and gas production in arctic areas is challenging due to harsh environmental conditions. Pipeline burial and trenching in those areas are now one of the prime methods to avoid ice gouge risks and other threats. Thermal management becomes critical when the ambient temperature is low such as the typical seawater temperature on the sea bed. The flow temperature and pressure affect viscosity of the fluid traveling through the pipeline and determines the state of the fluid (single or multiphase). The effect of freezing around oil and gas pipes in the vicinity of permafrost is considered as another concern for flow properties of oil and gas in arctic regions. Theoretical shape factor model has been widely utilized to estimate heat loss from buried pipelines. This study examines the validity of using this method for flow assurance calculations. Several steady state and transient experiments have been carried out to model the heat loss considering different parameters such as burial depth, backfill soil, trench geometries etc. Natural convection can play a significant role in the overall heat loss process from the buried pipeline. The total heat loss increases significantly when the backfill soil is loose or sandy. This paper illustrates the effects of heat conduction and natural convection in the heat loss mechanism from buried pipelines. The outcome of this paper will provide valuable heat loss models based on experimental and numerical analysis results. These outputs can be used largely in petroleum industries for designing pipelines in offshore arctic areas and to mitigate several flow assurance issues (e.g. wax and hydrate formation in the pipeline effectively). The methodology used in this research i.e. analyzing the experimental data with two steps of validation will ensure the validity of the proposed model. Using different parameters such as burial depths, trench geometries, and backfill soil this paper provides an effective model for the offshore pipeline design.

During oilfield development and production stages, the zonal rate and phase allocation often enables effective well and reservoir production management in multilayer reservoirs. Production allocation is necessary to reconcile oil, gas, and water measurements at all entry and exit points at all stages of reservoir development. Model-based quantitative interpretation of field production logging data is proposed as a tool to make more-informed decisions for water horizons isolation in a multilayer well. The conventional technique of zonal allocation from production logging data has been successfully used for decades. This approach is based mainly on the analysis of several types of logs including steady-state temperature profiles and may face difficulties related to the uniqueness of pay zone allocation profiling due to uncertainties in input data. This shortcoming makes it inapplicable in certain challenging cases. This paper focuses on one such case. Determination of zonal contributions in multizone multiphase wells from a limited data set is often challenging due to the complex nature of fluid flow under varying dynamic conditions and uncertainties. Therefore, the integrated analysis of transient measurements, including temperature, pressure, and rate, is suggested to mitigate the impact of such uncertainties. Using comprehensive hydrodynamic and thermal models in this process enables elimination of unrealistic or ambiguous interpretation scenarios that can arise from using simplistic methods. This paper illustrates the new workflow for joint analysis of temperature, pressure, and rate transient measurements acquired in an oil well during a multirate test in a multilayer reservoir using a production logging tool. The workflow is based on using in-house nonisothermal transient code for quantitative interpretation of the full field data. The interpreted data set includes distributed (logs) and station measurements (trends) that were used for quantitative analysis of pressure and temperature for both production and shut-in regimes. We also demonstrate how this approach enables treating challenging contradiction between spinner and other log data caused by the complex structure of the reservoir and wellbore flows. In particular, the paper addresses challenges and the value of quantitative analysis of the transient temperature profiles during shut-in with multiple crossflows. The paper concludes how joint quantitative analysis of temperature, pressure, and rate data, enables high-confidence zonal allocation and determination of hydrodynamic model in a multilayer reservoir.

Existing standards and codes do not comprehensively address and provide all necessary guidance and requirements for the design of Arctic offshore structures. Reliably assessing ice loads on offshore structures remains a challenge for industry, especially as "new" Arctic platform concepts are proposed for deployment in lighter ice operations, e.g. Arctic SEDU (Self- Elevating Drilling Units) and Arctic CSDU (Column-Stabilized Drilling Units). As a pragmatic solution, a comprehensive approach including relevant field measurements, physical model tests and numerical simulations is usually adopted in assessing the ice loads for a particular design. Field measurement results are limited in number and there is often uncertainty concerning actual ice conditions and load measurement techniques. Furthermore several data sets are constrained with proprietary restrictions. In particular no direct field data is available for the example "new" structures (SEDUs and CSDUs). Physical model tests always present challenges due to scale issues, ice property calibration, measurement uncertainties and high costs. Therefore, numerical simulations using the validated DEM tool based on the related field/model test data are anticipated to provide supplementary information for standards/rule-based designs.ABS has expended efforts to develop practical and advanced tools to assess the ice loads on offshore structures for several years. One promising numerical approach, a graphic processing unit (GPU) based Discrete Element Method (DEM) model, processes the computations in parallel and solves the DEM model with millions of particles for complicated ice-structure interaction problems, e.g. ice simultaneously loading on multiple legs and ice loading on a large CSDU. The paper presents details of the developing ABS GPU-DEM tool, status of the verification program, plans for the current and the future developments and applications. Included are brief descriptions of background technologies, an approach to derive the DEM model bonding strength inputs, and validation studies of ice breakage simulations based on the Bohai Bay Jacket ice data. The ice load simulations for fixed and floating structures, i.e. jack-up legs and the Kulluk floating drilling platform, are also shown to demonstrate the tool's capability and feasibility for Arctic offshore structure design. The interactions of ice and fixed/floating structures were analyzed, which provides useful references for future ice load modelling and offshore structure design.

Baltika, the world’s first oblique icebreaker designed to break ice sideways, left Murmansk on 20 March 2015 and headed to the Russian Arctic. The purpose of the three-week voyage to Kara Sea and the Gulf of Ob was to evaluate the vessel’s icebreaking performance and operational capability through extensive full-scale trials in challenging Arctic ice conditions. In the ice-free Barents Sea, the seakeeping characteristics of the asymmetric icebreaker hull were also evaluated in moderate seas. Performance trials were carried out in three different ice thicknesses, ranging from 40 cm thick saline sea ice in the Kara Sea to up to 1.22 m thick hard low-saline ice outside the Sabetta LNG terminal in the Gulf of Ob. During these trials, Baltika exceeded her design icebreaking capability of 3 knots in 1 m thick ice in both ahead and astern directions. In addition, the oblique icebreaking mode was demonstrated for the first time, and the vessel performed beyond expectations. While the main goal of the trial voyage was to confirm Baltika’s icebreaking capability, both the vessel’s crew and the designers gained considerable operational experience during the daily operations in the challenging ice conditions. After the best way to tackle obstacles such as ridged ice fields was discovered, Baltika was found out to be equivalent - sometimes even superior - to conventional icebreakers despite her lower propulsion power. There have always been those who have doubted the feasibility of the oblique icebreaker concept. The extensive full-scale ice trials in the Russian Arctic have shown that Baltika, the first icebreaker with an asymmetric hull, could not only break ice sideways, but also sometimes out-perform conventional icebreakers in other operational situations as well. The concept is thus seen to hold potential for a number of missions such as escort and port icebreaking and in offshore projects.

This paper summarizes the shore crossing options and considerations associated with Arctic subsea pipelines. A summary of what has been installed as well as other options not yet installed are covered. Some options have been ruled out for some projects, and while at the same time, they are either actively being pursued or may be in the process of consideration for other projects. Offshore project development in the Arctic may utilize pipeline tiebacks to shore. These tie-backs will require a shore crossing transition. There are design aspects for Arctic shore crossings that are similar to non-Arctic conditions. However, in many locations in the Arctic, there are unique Arctic- specific conditions that will influence the shore crossing design details. These Arctic design influences may be of a technical or non-technical nature. Both types of influences may require consideration of technologies and techniques that might not otherwise be considered for non-Arctic locations. These influencing factors will affect almost every aspect of the work as follows: pre-planning work, which includes geophysical and geotechnical site investigations the design details for the shore crossing, which is the ultimate goal of the work construction techniques, which are required to bring the design to fruition operating requirements and monitoring for the life of the development One of the main conclusions is that the project and site specific conditions will influence the available shore crossing design options for a project, the option that is ultimately selected for a particular Arctic pipeline project, and the design details required for that project. The site conditions at one project location may be different than the site conditions at another project location, regardless of distance between the two projects. While two different projects at two different locations may utilize the same shore crossing method, the relative costs between the two project's shore crossings may be different due to more conducive site-specific conditions at one location versus less conducive site- specific conditions at the other. There are several Arctic subsea pipeline projects with shore crossings that have been successfully designed, constructed, and have been operating without incident for more than 15 years. Each illustrates that, despite the increased costs and effort compared to non-Arctic shore crossings, the industry has "been there and done that" safely.

Wave driven iceberg and bergy bits’ impact load with an offshore structure is an important design concern. Hydrodynamic interaction between iceberg / bergy bit and an offshore structure in close proximity is an important factor that governs the impact load. Recently, a set of experiments has been conducted at Ocean Engineering Research Center (OERC) at Memorial University of Newfoundland to measure the wave loads on different sized spherical ice masses at different proximity to a fixed structure. A six component dynamometer was used to measure the loads in a quasi-static manner in six regular head waves. The objective was to investigate change in wave loads as the ice mass approaches to the structure. The experimental results show that the distance to wavelength ratio dictates the corresponding wave loads in horizontal and vertical directions. The mean drift force in the horizontal direction becomes negative (against the direction of wave propagation) for most of the cases when the body is close to the structure. Also, as the body is positioned closer to the structure, the non-dimensional RMS forces in the horizontal direction decrease and the non-dimensional RMS forces in the vertical direction increase.

Recently turret-Moored FPSOs have been used in many deep water developments worldwide, with consideration of dis-connectable turrets for harsh environment with iceberg conditions. This trend makes the interactions between FPSO and risers system more important. Further, Steel Lazy Wave Risers (SLWR), which is a compliant variant of the mostly commonly used Steel Catenary Risers (SCR), is becoming an attractive riser option. The paper provides a review of two riser systems that can be considered for turret-moored FPSOs, and specific emphasis on Steel Lazy Wave Risers. A detailed case study of Steel Lazy Wave Risers for a typical turret moored FPSO with dis-connectable turret is presented. The design drivers are; to reduce the turret pay load, especially in disconnected condition, the selected riser system should have minimum tension variation so that the disconnected turret is stable and an optimum installed overall cost of the system. To achieve the design objectives an improvised Steel Lazy Wave Riser configuration called "Tethered Steel Lazy Wave Risers" (TSLWR) is developed. Pros and cons for TSLWR are discussed, with consideration of the particular challenges of turretmoored FPSOs with large floater motions, hang-off geometry constraints at turret, hang-off loads, riser interferences, risers pre-installation, and turret disconnection constraints.

Due to a lack of data, currently (and justifiably) conservative ice load assumptions are made in rig assessments allowing only very small floe sizes to contact non-Polar classed drilling rigs. In September 2015, in cooperation with the Norwegian University of Science and Technology (NTNU) and the Swedish Polar Research Secretariat (SPRS), ExxonMobil and C- CORE participated in the Oden Arctic Technology Research Cruise. A distinguishing aspect of this Cruise was: (a) performing ice management trials using two icebreakers, the Oden and the Frej; and (b) instrumenting the Frej, i.e. the secondary icebreaker and therefore collecting first-of-a-kind local ice load data during stationkeeping in managed ice. Unlike all prior data behind code pressure-area curves, which are based on transit in unmanaged ice and ship ramming, the new data are in managed ice field, representing true pressures and forces on a drilling or production vessel in a stationkeeping mode (moored, dynamically positioned (DP) or DP assist). This paper describes the design, installation and calibration of the Frej load measurement system. The system consists of an array of over 160 strain gauges installed over three panels on the bow and shoulder of the vessel. Prior to sailing, physical calibrations were performed as quality checks of the gauge installation and to benchmark finite element (FE) models used afterwards to convert measured strains into hull local ice pressures. More than 260 hours of local ice load data were collected throughout the program including measurements while stationkeeping in managed ice conditions in addition to actively managing ice and transit. The system remained operational through the entire field program without loss or damage to a single strain gauge. The data collected can contribute toward demonstrating the ability of existing rigs to resist some degree of managed ice, and hence can open the possibility for drilling season extension beyond open water, which can have a significant economic impact on arctic drilling. The resulting pressure-area curves will be the subject of a follow-up publication.

When designing oil and gas platforms for offshore arctic and subarctic regions, operators may need to consider the influence of iceberg impacts on optimal structure configuration and ice strengthening requirements. Icebergs have complex and varied shapes, are mostly underwater and are usually moving in currents and waves. Previous iceberg profiles developed from sonar profiles and above water measurements have varying limitations in accuracy, necessitating approximations in modeling both the overall and local shape of the icebergs. A field program was conducted to obtain high resolution full three dimensional (3D) iceberg profiles that allow for detailed modeling of icebergs. Following the field program, a number of studies were conducted to utilize this data to develop improved tools both for calculating design iceberg impact loads for offshore structures and for improving ice management. One of these studies, described here, entails development of a full 3D timedomain simulation model for icebergs impacting fixed and floating platforms in 6 and 12 degrees of freedom (DOF) respectively. A key requirement of the model is that existing scale dependent models for global ice crushing failure pressure can be incorporated. The main objective in developing the model was to provide a tool for evaluating specific iceberg impact scenarios that considers 3D effects and requires fewer assumptions regarding interaction mechanics than previous methods. In this paper, the basic framework of the 3D time-domain model is described, and initial model results are presented for several example applications: icebergs impacting a cylindrical GBS, a stepped cylindrical GBS and a moored spar floating production unit (FPU), the probability of iceberg pinnacles impacting a platform topsides, and subsea interactions. For the cylindrical Gravity Base Structure (GBS), sensitivity analyses are presented for ice strength, friction, drag coefficient, damping coefficients, platform diameter and iceberg velocity.

The goal for TTRD wells and deep kick-off sidetrack wells is to reach the pay zone with one single section. A geological target is often located at a significant distance from the kick-off point, demanding a well path profile with a medium/high radius curve followed by an extended horizontal section. In the past a two run strategy was considered to be the right choice for similar well profiles in Gullfaks field: a motor BHA was used to drill the curve, and a rotary steerable system to drill the horizontal interval. Introduction of the new high dogleg rotary steerable system made it possible to apply the benefits of continuous rotation (faster drilling, smooth wellbores with full directional control and better hole cleaning) to trajectories previously only drillable by downhole mud motors due to high dogleg requirements. The paper describes a new approach for drilling challenging highly deviated reentry wells in one run on example of a one particular TTRD well drilled in North Sea.

Acoustically the submerged components of an Azipod propulsion unit comprise two uncorrelated noise sources, namely the propeller and the electrial motor. The propeller hydrodynamic noise is highly dependent on the load & speed whereas the magnetic noise of the electric motor exhibits a smoother dependency on the load & speed. The electromagnetic noise of the motor is highly dependent on the converter supply properties such as the number of voltage levels and current/voltage modulation parameters. The paper deals with the challenge of estimating the total underwater sound emission of an Azipod unit using both the airborne sound power measurements and underwater sound emission simulations and current hydrodynamical tools available. The airborne electromagnetic noise emission of the unit can be measured at a factory testbed using the designed converter supply together with correct shaft loading. Sound intensity based methods are favoured in the paper due to their ability to exclude the extraneous noise from the results (factory background noise & noise from the loading machine). Once the airborne noise figures are obtained, a conversion to corresponding underwater noise figures is needed. This is accomplished by computing the airborne and underwater noise radiation with same electromagnetic loading using FE-method for the structural dynamics and BEM for the acoustic radiation. The conversion factor K from airborne to waterborne sound emission is finally obtained for each of the electomagnetic excitation patterns. The accuracy or goodness of K is then validated by comparing future underwater noise measurements during sea-trials and the measured airborne emission at the test floor. Separate analysis of hydrodynamic acoustic characteristics are performed with three different tools and finally combined to total URN level with electromagnetic noise emission estimation. In this work, the underwater fluid loading on the Azipod unit surface plates is included by using a very simple approach, which is to be addressed in future studies.

A Common Operational Picture (COP) can generally be described as a system of hardware and software that produces a shared display of information to facilitate situational awareness and decision making. A brief history of the development and use of COP technology in Arctic operations is provided. Experience and learnings from ExxonMobil's research into the use of COPs in ice management and Arctic floating drilling is described. Experience gained from simulations, desktop studies, and field observations is used to frame preliminary functional requirements for such technology needed for future Arctic floating drilling operations in high concentration ice. The COP must facilitate the planning and execution of complex and remote operations with many geographically distributed assets (e.g., drilling rig; icebreakers; shore base; manned or unmanned aviation) and stakeholders (e.g., icebreaker captains, drilling management, ice analysts, weather forecasters) at times communicating over limited bandwidth channels. The COP will serve to collect, store, communicate, and display the necessary data and information. The role of COP components (e.g., databases; communication network, displays) is described and functional requirements are outlined.

In this paper, the relationship between the rudder lift force and ice loads on the stern shoulder of a vessel hull is studied. The study is based on full-scale measurements with research vessel SA Agulhas II on Antarctic voyage 2012-2013. The results show that rudder lift force has a significant effect on the ice loads on the stern shoulder region.

A floating platform in deep water Eastern Canada is required to withstand iceberg loads and/or be disconnected and towed away only in the event of very large approaching icebergs, leaving the mooring lines and risers in-place, support large topsides and provide large quantities of oil storage in the hull. Additionally, the platform should provide low motion response to storm and ice loads to maximize the operational uptime and facilitate the use of a large number of different riser systems including steel catenary risers (SCR). This paper presents the details of a Disconnectable Concrete Spar FPSO platform that has been configured to satisfy all the above requirements and is able to be constructed locally in Eastern Canada. The paper describes a number of key features of the Spar shaped hull, mooring and riser systems that are specifically designed to withstand large iceberg loads and other environment loads while maintaining the characteristic low motion response to storm environments. The design helps to minimize disconnection frequency due to approaching icebergs and disconnection may only be required for very large icebergs or ice islands. Additionally, the system has been designed to minimize disconnection and reconnection time.

Current design standards for ships operating in ice-covered waters involve great deal of uncertainty in the associated risk level. The main reason for this uncertainty is the stochastic nature of ice failure process during ice-structure interaction, which means that the load imposed by ice on structures cannot be accurately defined. Therefore, rule requirements by Classification Societies define the pressure loads on patches of predefined sizes, which cannot accurately represent the real ice-structure interaction process. To partly overcome this limitation, this paper proposes alternative approaches for applying pressure, discusses the relevance of these loading scenarios and compares the resulting structural damage to the one obtained with current design approach.

In this paper, we present a successful implementation for the development and deployment of a system that automates and simplifies the surveillance and optimization workflows for the gas lifted wells at a platform in the Gulf of Mexico. As with other "digital oil field" type systems, the success of the capability deployed, called Gas Lift Optimization Workflows (GLOW™), required the use of diverse and more-than-capable library of techniques, algorithms, and methods that already exist in the fields of optimization, machine learning, signal processing, physical modeling, and numerical simulation. We adopted a philosophy in GLOW of relying on our understanding of the underlying physics as much as possible to achieve our goals. We found that most of our problems, like the diagnosis of steady-state gas lift injection through multiple valves or solving for the optimal allocation of gas lift to every well, could be solved to an appropriate level of accuracy with physical models that are automatically matched to well-test and real-time data coming from the field using non-linear regression techniques. We resorted to using statistical modeling approaches, like Naïve Bayes classification for slugging detection or Kalman Filtering for reservoir pressure prediction, in situations where uncertainty precluded the use of physical models. The benefits of this system include production uplift, increased operator efficiency, optimal use of gas lift experts, and timely mitigation of issues The key challenge in developing GLOW™ was to figure out how to stitch some of these methods together and create a system to enable operators and gas lift specialists to monitor and optimize all the gas lifted wells given limitations in data quality and coverage.

Usan, a deepwater field located offshore of Nigeria, commenced production in February 2012 with development drilling to be completed in 2016. The field has 2 subsea flowline loops with 4 risers giving the flexibility to flow wells through two different risers. Due to the constrained flowline capacity, optimization of well routing and drillwell sequencing became critical to sustain the remaining drillwell campaign while maximizing base production and incremental uplift. The adopted approach by the Production and Reservoir Engineering teams was to utilize the Integrated Production Modelling (IPM) software suite (PROSPER, GAP & RESOLVE) to ensure optimal well mix and flow stability. A systematic approach of continuously testing various routing scenarios of wells within the different production loops was applied to minimize production back out loss due to system hydraulics during the streaming of new drillwells. Different ramp-up scenarios were also tested for the new wells to minimize back-out on base wells. Due to variations in fluid properties, reservoir pressures, depletion strategies and loopline distance, the system needs to be re-evaluated frequently. With over 50 routing sensitivities assessed at each evaluation, identifying and implementing the optimal routing/configuration became critical. Production optimization using the IPM model has led to higher FPSO incremental rates from new drillwells due to optimized well routing within the production risers. This has also helped to sustain the ongoing drilling campaign in the Usan field and improved the economics of the overall project. This paper describes how IPM software was used to maximize incremental production from new drillwells.

Today, directional drilling, with no doubts, has brought massive benefits –ultimately has helped to increase reserves, increase production with even fewer number of wells, reduce cost, reduce footprint and environmental impact. With its enormous benefits also is a risk –the risk of well collision. With the advances made in directional drilling and wellbore surveying the probability of occurrence has been reduced significantly and both service companies and clients have come up with policies to ensure that the risk is kept at ALARP. Today, three parameters are widely used for collision risk assessment: separation factor, minimum separation distance and centre-to-centre distance. There are different methods used for calculating these parameters and the minimum acceptable value are defined by clients and directional drilling service companies. The deepwater (GoG) development under review in this paper was developed using the subsea production manifold system. The wells were drilled and tied through a jumper to the manifold; each manifold has six slots. This implied that for every manifold, at least six wells will be closely spaced and thus posing the risk of collision especially during tophole and surface hole sections. However, at the initial development plan, the well trajectories have been optimized to ensure there were little or no collision concerns as defined by the company rules on what is minimum acceptable separation factor and minimum separation distance. So deploying directional drilling technologies and high accuracy wellbore surveying tools, the initial wells were drilled without any collision concerns. However, 6years after the first oil, the asset management team has asked for in-fill wells in a drive to increase production and improve recovery. This brought with it special collision concerns; special because these wells are in production and are all tied to an FPSO. Any collision incident will be very catastrophic. This called for a thorough planning and a more systematic approach to ensure that the in-fill wells are drilled without colliding with existing wells. This paper is aimed at highlighting the systematic approach used to manage this inherent collision risks from the planning to execution of these in-fill wells. A total of 8 in-fill wells have been drilled successfully without any collision. The success of the systematic approach is largely from the synergy built amongst the client, the drilling contractor, the directional drilling and surveying company in developing and implementing it. At this point, it this has been proven that collision avoidance is not just about solving equations and making calculations (in fact there are different methods for calculating the three defining parameters) but a systematic procedure that must be put in place from the planning, execution to post-execution.

As hydrocarbon fields in production mature, the resultant increase in produced water poses a problem due to the ever-increasing costs associated with handling and separation. Current technology requires produced water to be brought back to a host platform or onshore from offshore reservoirs to address this issue of produced water separation and disposal. Significant interest within industry exists for Subsea Separation Technology, especially where current technology is challenged. The need for new or improved technologies is particularly salient when considering the topic of seabed discharge of produced water. Interest is further magnified in regions such as Trinidad and Tobago, where exploration activities in deepwater blocks have commenced and subsea processing could prove advantageous when compared to topsides. This paper will discuss the need for development and testing of a subsea produced water treatment system for seabed discharge and the ongoing efforts involved in commercializing this technology. Various existing subsea separation systems will be presented, with reasons why each has failed to render a solution to the issue of disposal of the produced water to the sea. A discussion will be made to illustrate the new era of linear separators, spherical separators, and compact flotation devices that may bring about a technology breakthrough for allowing subsea separation and discharge of the environmentally clean produced water to be discharged at the seabed. Oil-in-water sensors enabling continuous measurement of produced water discharged at the seabed will also be introduced to illustrate current technology developments. The sensors' design basis and criteria are compared to existing discharge limits in the U.S. Gulf of Mexico and Trinidad and Tobago to highlight the benefits of their use in these regions. In particular, four (4) sensor technologies subject to bench-scale testing in mid-2016 and their working principles are outlined.

The westernmost wellpads of Alaska's Prudhoe Bay field, known collectively as the "West End," operate under two primary constraints: gas lift supply pressure and a shared production line velocity limitation. Comprised of four primary wellpads with close to 100 operable wells, the West End produces ~38,000 bopd, approximately 12% of Prudhoe Bay's daily output. These wells have the lowest gas-oil ratio of all Prudhoe wells – a field generally considered gas handling limited – making them all the more important to have online and optimized. In the past, production sorts (rankings) based on total gas-oil ratio, rules of thumb, and adjustments to individual well gas lift rates were the answer to production optimization. However, over time, production changes occurred that went unexplained, or at least unproven, under certain operational conditions. Additionally, it was never known if the wells were optimized as one congruent system. To address this uncertainty, an industry proven physics based multiphase flow simulator was used to construct two models, one representing the production system and the other representing the gas lift system. The two were then coupled, creating a dual model that allows for the production and gas lift halves to work in tandem and respond to one another. The combined model is now an integral piece of an overarching production model built by BP to model and optimize the vast production system – from sandface to first stage separation – of Prudhoe's surface kit of 47 wellpads and seven production facilities. The model is used on a weekly basis to help optimize West End production and in pipeline replacement studies. Additionally, the model has been used to show that the overall offtake rate along the gas lift supply line is less important than the offtake locations. Using the model, operating limits are being defined for the field operations personnel and production engineers to stay within during certain field condition scenarios which would affect gas lift supply pressures. Such a model could be useful for any production system that is constrained by gas lift supply pressures. It is the aim of this paper to describe the building of a model that successfully captures changes in production to a very large set of interconnected gas lifted wells due to fluctuations in gas lift supply pressure, how it is applied, its successes, its limitations, and its future improvements.

The deployment of scale squeeze treatments in subsea horizontal wells has always presented a challenge in terms of understanding the location of injected fluids vs the location of the produced water where scale formation will occur. Over the years software packages such as Eclipse has been able to provide valuable information on the possible placement options for such wells when production logging tool (PLT) data have not been available. The development of multi-lateral drilling/completion technology has further complicated the placement challenges in such wells. In this paper Eclipse simulation data has been linked to SQUEEZE designs software for two subsea production wells completed with multi laterals and sliding sleeves to allow selective placement of the squeeze treatment. The objective of the study was to evaluate the options of bullhead deployment in terms of both laterals being open during the squeeze vs two squeeze stages being sized and selectively placed into each lateral again via bullhead deployment, but this time using the sliding sleeve technology to divert the chemical. Information on cross flow issues, the pump rates required to allow effective placement are presented, along with the differences in chemical volumes, pump time and soak times required for the two potential treatment options. The finding from this study show the clear advantages in terms of treatment volumes, reduced clean up time and extended treatment life (reduced intervention frequency) of bullhead deployment of two squeeze steps, one to each lateral, achieved by utilizing the sliding sleeve technology in these two production wells.

The Chestnut field produces from two subsea, non-isolated commingled wells tied back to the Hummingbird FPSO. A steep decline in production was observed in Q1 of 2014 in well 22/2a-11x which was attributed to the formation and deposition of barium sulphate scale in the well and confirmed through a new method developed for the determination of seawater breakthrough onset in commingled wells (Chen 2015). Following this, an elevated temperature barite dissolver treatment was designed so as to try and remove the scale and allow for a subsequent scale squeeze treatment to be applied. Deployment of the dissolver and scale squeeze treatments, however, presented several challenges, the main one being that the 22/2a-11x well cannot be mechanically isolated from the other well in the field for a treatment to be bullheaded. In addition, the common flowline was known to contain sand and the well's xmas tree design and vicinity to the FPSO meant that any chemical treatments needed to be delivered down the production riser; the limited deck space on the FPSO rendered this a particularly complex operation. A supply vessel had to be modified to accommodate mixing, storing and heating capabilities, with heated dissolver being transferred to the FPSO via a suitably rated hose over open water. A unique delivery approach was developed to allow the successful placement of the scale dissolver and scale squeeze treatments in well 22/2a-11x through the use of a non-aqueous liquid "plug" in the common flowline; the combined treatments led to a doubling in the well's production compared to oil rates prior to the intervention. This paper presents the difficulties associated with delivering these multistage treatments and the applied engineering solutions that enabled effective placement of both the scale dissolver and scale squeeze in this subsea well. In addition, lessons learned in the process as well as an evaluation of the placement strategy on the efficiency of the scale removal and squeeze treatments will be discussed.

One of the major challenges in mature oil fields is to improve recovery from existing fields by developing and implementing new technologies that make operations efficient and cost effective. For a reservoir with a water or gas drive mechanism, the mobility ratio between oil and water or gas becomes more critical due to the lower viscosity of water or gas. Observably, breakthroughs can occur within relatively short periods of production time. Once breakthrough occurs, gas or water production can rapidly dominate production prompting well intervention or the shutting-in of production, leaving unrecovered oil behind. Inflow control device (ICD) and autonomous inflow control device (AICD) have shown oil production and recovery can be increased significantly with better inflow control/pressure regulation along the lateral, which to some degree has resulted in breakthrough delays. However, neither ICD nor AICD are able to shut off unwanted gas and water production completely. The autonomous inflow control valve (ICV) offers the functionality of conventional ICD and can actively shut off unwanted fluid completely. The paper describes the development of Autonomous ICV, experimental test results, and preparations prior to the completion installation. The main challenges and conclusion from the field tests are presented and discussed based on the initial flowback data where the functionality of Autonomous ICV was verified, i.e., by shut-off of low viscosity fluid, such as water, and opening for oil with higher viscosity.

Many people believe in the benefits of incorporating Managed Pressure Drilling (MPD) into well planning, which has been done onshore for a long time. In recent years this technology has been transferred to offshore drilling vessels. However, there appears to be some hesitation in widely implementing MPD solutions offshore, due most likely to perceptions regarding complexity and cost of integration. This paper has been written to communcate the scope associated with implementing a Controlled Mud Level (CML) MPD technology onto an offshore drilling vessel in order to allow Operators and Rig Contractors to evaluate the level of complexity involved. This paper emphasizes that the technology has now been integrated onto several rigs, allowing the CML provider, Rig Contractors and Operators to work out best practices for technology implementation. Integration of a CML system is now accomplished with standard products, a well-defined scope and experience-based understanding of what is required.

This paper illustrates what is required to select and install an MPD system on a deepwater drillship by following a recent example of such an installation. It addresses some of the things that should be considered when choosing equipment to ensure that the equipment will be safe, properly sized, efficient, redundant, and capable of performing all the functions expected of an MPD operation. The relative merits of choosing equipment from various suppliers instead of a single source provider, as is more commonly done in the industry, is examined. Installation and incorporation into the rig package and how conventional operations are impacted are also discussed.