Shell (Germany)

An analytical review of the prospects to use liquid friction bearings in rotation drives of promising wind power generators is carried out. The description of the structure and functionality of an experimental stand for studying the characteristics of hydrodynamic satellite axle beds of a planetary gearbox of a powerful wind turbine drive is presented. The method of measuring the main parameters and methods of processing experimental data are considered. The results of experimental studies are analyzed, and recommendations are proposed for ensuring a long-term resource in conditions of the required load capacity and energy efficiency.

Abstract Fluid characterization is a key input into reservoir and field development studies and effective wells and reservoir management. Thus, the importance of acquiring representative reservoir fluid samples cannot be over emphasized. Fluid samples acquired from the reservoir may be contaminated by drilling fluid. However, with advancements in reservoir fluid analysis and characterization, it is possible to numerically clean contaminated reservoir fluid samples. This paper presents a case study of the effects of Oil-based drilling Mud (OBM) contamination on gas condensates fluid properties from a Deepwater turbidite reservoir in Nigeria. Four contaminated samples acquired from this reservoir were studied. The results show that drilling fluid contamination has a marked effect on key gas condensate fluid properties such as the Condensate-Gas-Ratio (CGR). The higher the contaminant the higher the CGR of the contaminated and resultant cleaned fluid. Numerical cleaning of OBM contaminated gas condensates does not guarantee obtaining a fluid model that is representative of insitu uncontaminated reservoir fluid. A linear relationship was observed between the cleaned fluid CGR and Saturation Pressure (Psat) with respect to the contamination level. Extrapolation of this relationship to 0% wt. contamination yields a CGR and Psat that were likely to be indicative of insitu uncontaminated fluid CGR and Psat. This formed the basis for a low case PVT parameter estimate, thus enabling the definition of suitable fluid parameter uncertainty ranges. The paper also highlights the importance of acquiring multiple fluid samples and benchmarking fluid description against possible analogues within the same and/or similar geological setting to enable the development of possible insights that may support and improve the analysis.

Abstract Glass Reinforced Plastic (GRP) pipes are widely used as an alternative to metallic piping in challenging environments, such as concentrated acids. However, compatibility with the environment is typically described only in qualitative terms, and non-destructive inspection techniques do not provide data that can be used to accurately quantify in-service degradation. Consequently, remnant life prediction as the basis for maintenance and replacement of non-metallic piping presents a considerable challenge. The ISO-14692 standard provides a methodology for qualification of GRP piping that uses data from tests carried out with potable water, which can be scaled using a factor for other service fluids, although a default value of 1.0 is commonly used. This paper extends that design practice specified in ISO-14692 by incorporating the chemical compatibility factors as described in EN 13121 for design of GRP tanks and vessels. This procedure is used to calculate a chemical de-rating factor for long-term hoop stress, in addition to the standard design lifetime factor defined in ISO-14692. The combined de-rating relationship is repurposed to evaluate the amount of degradation under the actual service conditions experienced by the piping. Examples of this approach are provided for non-metallic piping carrying a range of service fluids in an operating plant.

Abstract Since 2019, a 340K type of Hydraulic Workover Unit (HWU) has been contracted by the Operator for production protection in case of ESP failures, primarily for the offshore assets. Due to the nature of contract and scope, there were times when the HWU was in standby mode while waiting for the next ESP replacement scopes and/or for the offshore vessel to be made available. When there was a requirement to recomplete a land gas well ‘S’ to increase gas lift supplies, an opportunity was seized to utilize the HWU to execute the recompletion scope. Well S was a 4,300m deep exploration well that was drilled and tested in 2019 with a 2,000HP land drilling rig. The well had two zones of open perforation and it was then suspended with a combination of inflatable cement retainer, cement and sand plugs, and another V0 hydraulic plug above it. The first operational scope was to prepare the wellbore by clearing the access for the perforations, and the second scope would be the recompletion operation. The opportunity was clear, but the solution wasn’t as straightforward. Originally this recompletion was planned to be executed with a land rig, but scheduling conflicts meant that the land rig arrival was delayed by a few years. The team saw the opportunity to maximize the assets at their disposal but there were two main challenges in realizing this opportunity. First, the offshore setup HWU required significant modifications to operate on land environment. This included adding components in the peripheral e.g. a crane, tanks/temporary pipe works and accommodation cabins. The second challenge was to assess and equip the unit that was supposed to perform non-complex hoisting operation, to be able to execute the recompletion scope which included fishing and milling, wellbore clean-up, TCP operation, and installing completions. The other important element of the HWU utilization is that it has a lower carbon footprint as opposed to drilling rig. In average, the fuel consumption of the HWU is nearly half of 1,500HP drilling rig and even though drilling rig operational efficiency is generally higher, the overall emission of HWU would still be lower in this case. This paper describes the requirements set at the planning stage, to ensure that the minimum technical requirement was defined and that the project was competitively scoped. It outlines the challenges encountered in the preparation stage as well as in the operation stage, and how they were addressed, resulting in a safe and successful campaign and "out-of-plan" gas to support the production. Furthermore, this paper examines the boundary of the Hydraulic Workover unit and illustrates how thorough planning and risk assessment were critical for the non-routine activities.

Abstract Well A, a Brownfield offshore oil producer in Brunei, was shut in due to multiple leaks in the tubing. The well was drilled in 2000, so was facing common issues associated with depletion prior to shut-in. Production from the well was restored by installing an innovative thru-tubing retrofit gas lift system, allowing for injection of lift gas below the production packer, while simultaneously restoring tubing integrity by isolating the leaks. The goal of the rigless intervention was to restore tubing integrity by installing an ISO 14310 V0-validated gas-tight straddle across the leaks. The straddle also serves as a retrofit gas lift system, enabling delivery of lift gas below the production packer, just above the horizontal open hole gravel pack section. The straddle directs lift gas down an inner string hung from the lower packer with an installed gas lift mandrel on the bottom of the tail pipe, delivering lift gas below the production packer. The straddle features internal flow paths, allowing produced fluid to flow through the straddle back towards surface. Once installation was complete, the new gas lift valve was installed 200 m TVD (true vertical depth) deeper than the lowermost side pocket mandrel. During the initial well test, lift gas was injected down the casing and entered the production tubing through the leak points and SPM, which were contained within the straddle assembly. The upper and lower packing elements in the straddle directed all gas through the crossflow sub and into the inner string suspended from the lower packer. A slim gas lift valve was connected to the downhole end of the tail pipe. By injecting lift gas in the lower completion, hydrocarbon was unloaded from a deeper depth than would have been possible using conventional gas lift. Within four hours of starting lift gas injection, Well A was flowing steadily with 900 kPa of flowing wellhead pressure (FWHP). The well was then shut in, pending a full well test. This novel approach helped avoid an expensive workover and minimized runs in hole by incorporating the gas lift retrofit system into the straddle isolating the tubing leaks. This installation was the first in Brunei that placed the lift gas injection point beyond the production tubing in a horizontal well. As a result, a well that had been shut in for five years was re-instated and production was further optimized by deepening the lift gas injection point 200 m TVD below the lowermost side pocket mandrel.

Abstract Injection of water, gas, or steam, into subsurface reservoirs causes an increase in the reservoir pore pressure, with a corresponding impact on the in-situ reservoir stress state. This can lead to tensile fracturing, shear failure or a combination of complex failure mechanisms, depending on factors such as rock mechanical strength, elastic properties, pore pressure & magnitude of total stresses. Reservoir shear failure due to water injection/disposal can result in faulting or fault re-activation, which may present a containment risk if propagated into the caprock or under burden. A robust assessment of shear failure is usually challenged due to limited or unavailable geomechanical core measurements that fully assess lifecycle impact of stress and pressure changes. This paper demonstrates a deterministic and probabilistic methodology in the assessment of formation shear failure due to water disposal, that manages the uncertainty and constraints posed by limited geomechanical data. This approach employs the Mohr-Coulomb failure criterion in evaluating the tendency for shear failure in two water-bearing reservoirs A1 and A2, identified as Produced Water Disposal/Re-injection reservoirs in X-field, a brown field Onshore Nigeria. It integrates offset LOT data, log data, formation pressure data and empirical relationships between geomechanical and petrophysical rock properties, to establish rock strength parameters, the associated uncertainties, and combining them probabilistically through Monte Carlo simulation to determine the probability of shear failure in reservoirs selected for produced water disposal. Results indicated the key uncertain parameters impacting this assessment and also showed minimal probability of shear failure in both reservoirs; however, recommendations were provided to maintain a safe operating window and why an integrated approach to optimization is key to success.

Bubble formation in transformers could lead to their failure, resulting in severe outages in the electricity network. Hence, understanding the parameters that impact the bubble formation process is crucial to maintain the transformer’s dependable operation. Commonly, mineral oil and non-thermally upgraded Kraft paper have been used as the insulating materials for power transformers, and the risk of bubble formation has been studied for this material combination. However, new insulating liquids such as esters and gas-to-liquid technology-based oils are recently gaining more popularity and studies on bubble formation for these alternative liquids are limited. In this paper, the impact of alternative liquids on bubble formation has been investigated by using a small-scale test tube-based system. Studies have shown that when considering the water content in the paper at the time of bubble formation, the bubble formation temperature is comparable across different liquid types.

Abstract Discovering new oil and gas resources is the key for any energy companies to sustain or improve the hydrocarbon production. However, it is evident that most Exploration & Production (E&P) companies have reduced their exploration investment in recent years and the downturns have contributed to the strain. Therefore, it is critical to choose the strategy and allocate budgets efficiently to make sure the best possible return in the exploration sector. Recently, the Operator restarted the exploration campaign in the deepwater territories of Brunei water, and it was key to leverage the learning curve from the Operator's global experience where essential strategies for cost reduction have been effectively implemented. The Operator has extensive deepwater drilling experience in Asia Pacific region as well as globally, where operational best practices are being replicated in the effort to standardize the Operator's deepwater activities. The Fast-Drill method in the riserless drilling section was identified to be a valuable replication in this part of the globe as it has proven to add values in other regions. The Operator has long concluded that the use of weighted mud (dynamic kill drilling, DKD) in the riserless section contributes considerably to the high cost of subsea exploration drilling. In anticipation of the shallow flow event and to mitigate subsurface uncertainties, the usual Pump-and-Dump method necessitates a substantial contingency volume of DKD mud. To reduce the volume of DKD mud required, the Fast-Drill method was employed instead of the Pump-and-Dump approach. Fast-Drill refers to the method of drilling riserless with seawater at high penetration rates where cutting loadings that are created by fast penetration rates results in the required equivalent circulating density (ECD). The Fast-Drill method has been implemented in two wells in Brunei and the results have been favorable. Among the benefits found were reduced rig time, significantly lower mud costs and the avoidance of gumbo. Borehole stability was maintained, and the hole was cased-off without difficulty. This paper describes the requirements set at the planning stage, to ensure that the project was competitively scoped and that it adhered to the Operator's global standard deepwater operations practices, following a franchise concept. It outlines the challenges encountered and how they were addressed to successfully implement the Fast-Drill approach. Additionally, this paper examines the advantages of this method and illustrates how thorough planning and risk assessment were critical for a safe and efficient execution.

Summary Oil and gas has a long rich history in the industry. As such, there is significant reliance on legacy system as part of a mature business process. There is a growing shift towards low-code or self manage solution, it becomes important ensure there is an ecosystem to support the change to fully leverage the trend.