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Results
Abstract Floating LNG (FLNG) technologies are being deployed to monetize mid-sized offshore gas reservoirs, avoiding constructing a sub-sea gas pipeline to a land based LNG facility and export jetty. A previous OTC-Brasil paper (OTC-26158 Gas Pretreatment Considerations for Floating LNG) has discussed marinization and pre-treatment options available for FLNG, and an OTC paper (OTC-27940 Liquefaction Technologies and Mechanical Drive Considerations for Floating LNG) has discussed space, weight, and safety consideration in liquefaction technology selection. This paper is a continuation, focusing on the thermodynamic and efficiency considerations of the liquefaction technology options. For those not familiar with the previous work, there is some discussion of the marinization and safety drivers within the focus topic. Offshore liquefaction technologies are often novel and many lack offshore references. The available offshore liquefaction technologies will be presented by Licensor and Technology name. Because of the diversity of liquefaction technologies, and to remain Licensor agnostic, the technologies are grouped by refrigeration method, with Nitrogen expander and SMR (Single Mixed Refrigerant) groupings of technologies examined with an emphasis on overall liquefaction efficiency, efficiency focus areas and design flexibility. DMR (Dual Mixed Refrigerant) is compared with the other two technology groupings. The paper provides an overview of the FLNG state of the art in liquefaction.
- Asia (0.68)
- South America > Brazil (0.67)
Abstract The primary objectives of well construction are to maximize reservoir deliverability, reduce remedial operations, and minimize nonproductive time (NPT) during the drilling and cementing process. Challenges associated with designing and delivering dependable barriers in deepwater environments include low bottomhole circulating temperatures (BHCTs), temperature variance, narrow pressure margins, annular pressure buildup (APB), etc. Cementing operations in these conditions should be engineered such that the equivalent circulating density (ECD) does not exceed the fracture gradient during cement-slurry placement. Additionally, lost circulation materials (LCMs) should be incorporated into the cement slurry to help control loss zones. This paper discusses the field implementation procedures and the cement-slurry design tailored for deepwater wells in offshore Brazil, which helped minimize risks and achieve the zonal-isolation objectives for extending the life of the well.
- Well Drilling > Pressure Management > Well control (1.00)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid management & disposal (1.00)
- Well Drilling > Casing and Cementing > Cement formulation (chemistry, properties) (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management (1.00)
Abstract The oil industry is going through a transformation in which reducing costs and increasing rig efficiency became paramount. In spite of this changing period, safety is, and must remain, the main concern for every offshore installation. In order to achieve a step change in safety during offshore ESP deployment in the North Sea, procedures and standard working instructions were reviewed and opportunities for improvements were identified. Innovative tools including a new cable spooling system and special subs were developed to increase safety and address operator concerns during ESP assembly. Special attention was also paid to the service quality and efficiency of the ESP offshore installation. The toolstore used during ESP completion was redesigned using lean and 5S techniques to optimize installation time, and a high efficiency tool was introduced to install cable protectors, considerably reducing ESP installation time. In order to monitor the changes and continue improving, a recording system was introduced and every offshore installation is recorded and used for assessment and training. The objective of this paper is to describe novel ideas developed in the North Sea that created a new level of safety and quality during ESP deployment. The improvements described in the paper might inspire other initiatives to increase quality and safety standards in the oil industry.
Abstract The new scenario for oil pricing, where the "lower for longer" seems to be the new reality, brought the necessity to revise all the costs associated to the subsea oil & gas production. More than just request price reductions on the contracting of the services; operators are now looking for the efficiency of the offered activities. In the well interventions’ world, the combination of cheaper and, still good in quality, services will not guarantee the lowest overall cost in a campaign. Aspects, such as, the existence of the built for purpose interventions features, experience of the crew in the well intervention operations, integration among services providers, the possibility of having fast change among down-hole conveyance systems, possibility of executing off-line activities and others, are what will bring a true safe, efficient and cost-effective operation. The third generation of the purpose built intervention semi-submersible (Q7000) is in the final stage of the construction and will be available to the market in 2018, bringing new technology enhancements and lessons learned from more than 15 years of continuous operations of the 1st and 2nd generation of the intervention semi-submersibles (Q4000 and Q5000, respectively). In order to have better operability in high winds seas and currents, Q7000 will incorporate modern automation, DP Class 3 classification and a customized design. As a vessel able to perform heavy work overs as well, Q7000 will have also a MODU classification, which will give the capability to take hydrocarbon returns to surface, as well as circulated well bore fluids. What differentiate a purpose built intervention semi-submersible from a typical drilling rig are how the associated intervention equipment is handled and the ability of the unit on offering off-line and parallel activities. In this sense, Q7000 will incorporate features to allow fast change-out among slickline, wireline and coiled tubing units; pipe handling system to increase the agility on the pipe runs; heavy lift subsea crane with active compensation, to allow off-line or parallels subsea activities; main derrick with active and passive compensation system; high capacity service crane, to allow simultaneous crane operations increasing the efficiency with mobilization and demobilization offshore; high capacity in terms of storage, including bulk, liquid and self-sustaining (fuel and potable water) storage; deck with high draft tonnage and a maintenance tower, to allow off-line testing of the subsea intervention package. The paper will give a detailed description of the design, capabilities and operational premises considered in the Q7000 development and will also illustrate, through a comprehensive exposition of the purpose built intervention features, how a purpose built intervention semi-submersible is able to deliver a more efficient and cost-effective subsea well intervention than a conventional drilling rig.
Synergistic Combination of Products for Optimization of Oil Well Production and H2S Reduction
Silva, R. C. (Dorf Ketal) | Pazinatto, M. (Dorf Ketal) | Marcorighi, J. B. (Dorf Ketal) | Dias, P. (Petrobras) | Sampaio, T. P. (Petrobras) | Bitencourt, J. (Dorf Ketal) | Hanna, A. W. (Dorf Ketal) | Paprocki, J. (Dorf Ketal) | Gomes, M. T. (Dorf Ketal) | Rocha, R. B. (Dorf Ketal)
This study presents the development of an innovative product which provides the combined functions of H2S sequestration and flow improvement in subsea applications. The product was applied and validated in an offshore field of Campos Basin for use via umbilicals in production wells. The methodology is based on stabilization of the non-nitrogenated scavenger in the presence of solvents consisting of compounds with different ionicities. The efficiency of the combined product was demonstrated in relation to H2S abatement in the organic phase, as well as to flow improvement. Evaluations of elastomer compatibility, solvent loss, heat and cold stress testing, particle size and corrosivity of metallic materials qualified the product for umbilical injection. Field validation was performed in a production well that presented flow instability, high viscosity and high levels of produced H2S. The combined product had a strong influence on water separation, promoted a good O/W interface formation, and showed high quality separated water, capacity to sequester H2S and reduce oil viscosity. In the approval phase for subsea application via umbilicals, the product achieved satisfactory results in all tests, satisfying internal specifications, and was considered suitable for this type of application. In the third and final stage, the product was tested in the field. The product application reduced the H2S level of the gas stream by approximately 90% and arrival pressure by over 20%, while well productivity increased by approximately 9%. The results obtained at the laboratory scale for product development match its performance in the field. Accordingly, the laboratory techniques used were shown to reliably reproduce production conditions, which is extremely important in the development of more effective products.
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Reservoir Description and Dynamics (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Corrosion inhibition and management (including H2S and CO2) (1.00)
- Health, Safety, Environment & Sustainability > Health > Noise, chemicals, and other workplace hazards (1.00)
- Facilities Design, Construction and Operation > Offshore Facilities and Subsea Systems (1.00)
Abstract As drilling muds evolve to satisfy well requirements, cementing preflush technologies need to change to ensure proper mud removal during cementing jobs. A new component—engineering-designed fiber—was added to a preflush fluid and tested in the laboratory, with promising results. The system was then implemented in Latin America. Obtaining proper mud removal is very important for achieving zonal isolation at cementing jobs. The new technology consists of the addition of an engineering-designed fiber to cementing preflush fluids to significantly improve the removal of nonaqueous fluids from the well during cementing operations. The fibers are compatible with both cement slurries and mud. They work by removing the mud from the casing or formation through two mechanisms: by mechanical cleaning and by attracting the nonaqueous compound of the mud toward itself by hydrophobic-hydrophobic interaction. Two different methodologies were used to evaluate the fiber's ability to enhance the chemical wash and spacer capabilities to clean and demulsificate the nonaqueous mud fluids. The laboratory tests were performed with cementing preflush fluids with and without the fibers. Results indicated that the preflushes with the fibers were able to clean and demulsificate the drilling mud much more efficiently than preflush without the fibers. Indeed, it was possible to optimize the amount of the preflush surfactants and still obtain excellent results. Some successful cases of field implementation of this technology corroborated the laboratory findings. In both cementing jobs, results indicated very efficient mud removal, and, consequently, zonal isolation and well integrity were achieved. The fibers were successfully pumped in a field in Latin America. This innovative technology is able to enhance cement bonding in both casing and formation and reduces potential remedial job costs in a wide range of challenging environments.
- Asia (0.68)
- South America > Brazil (0.46)
- North America > Central America (0.46)
- North America > United States (0.28)
Abstract Exercising environmental responsibility during decommissioning of old assets has become increasingly important during recent years. In addition to increasing awareness in the industry, regulators consistently update and review the regulatory requirements for well abandonment and asset decommissioning. Operators document liability costs related to decommissioning in their balance sheets. Advancements in project execution and technology adaptation have resulted in regularly scheduled reviews of these liabilities. However, an industry-wide initiative to improve decommissioning execution and efficiency has provided operators direct incentive to review these liabilities more consistently and thoroughly. This paper presents an integrated project methodology to help reduce liability costs by improving efficiency during the decommissioning phase. This integrated project approach typically begins with a detailed preparation/study phase to predict possible challenges, followed by a design phase for each stage of the project to identify potential costs savings. Well data and regulations are obtained and analyzed according to the specific geographical location and then categorized by the technologies and resources necessary for abandonment. During the technologies and resources phase, potential costs savings are included as part of the plug and abandonment (P&A) service solution. Wells identified as potential candidates for new technology applications are ranked and grouped according to the execution sequence. After this thorough categorization, time and costs estimates are produced for the candidate wells. This paper presents details of this integrated project methodology combined with recent key technologies to help improve efficiency during well abandonment operations in challenging scenarios. Case histories of the methodology application are also discussed.
- Production and Well Operations > Well Decommissioning (1.00)
- Facilities Design, Construction and Operation > Facilities Decommissioning and Site Remediation (1.00)
- Management > Professionalism, Training, and Education > Communities of practice (0.35)
- Data Science & Engineering Analytics > Information Management and Systems > Knowledge management (0.35)
Abstract The Campos basin is offshore Brazil in deep water and has unconsolidated formation characteristics. As such, wells located in this area are usually completed using sand control techniques. In the Roncador field, a vertical well with multiple pay intervals required a sand control solution for each zone. The primary challenge was to complete the total gross interval using a cost-effective sand control method that allowed selectively stimulating five zones and producing without solids. The largest multipurpose oilfield stimulation vessel in the world was assigned to perform its first deepwater offshore multistage fracpack treatment, which is a combination of fracturing stimulation and gravel packing. The five individual treatment stages were successfully performed as designed using multitrip sliding sleeves, which would later allow selective production of the zones. This allowed the operator to selectively isolate the intervals during completion of each one. In addition, this was the first time using a new sand-storage system and blender without a tube, which provided better reliability and a shorter response time. The operator and service providers collaborated to design the multistage well completion, providing both sand control and stimulation. The treatment plan was performed by this large modern service vessel without any reports of incidents or lost time. Additionally, all operational data were transmitted in real time to onshore operator and service company facilities. The five-stage treatment plan was performed in only 28 days, representing an estimated savings of 15 rig days for the operator compared to completions using a conventional treatment method. This paper reviews a deepwater Campos basin well that has multiple pays and potential sand production. The operator and service provider applied new completion technology for stimulation/sand control, which provided several advantages, including a significant reduction in required rig days. This was the first opportunity for the large stimulation vessel to conduct such an operation, and the performance of both the equipment and service crew was excellent.
- South America > Brazil > Rio de Janeiro > South Atlantic Ocean > Campos Basin > Block P-36 > Roncador Field > Maastrichtian Formation (0.99)
- South America > Brazil > Campos Basin (0.99)
Tracking of Materials and Equipment Used in Planned Maintenance Shutdowns on Offshore Platforms: An Approach using RFID
Soares, P. D. (State University of Northern Rio de Janeiro) | de Oliveira, C. M. (State University of Northern Rio de Janeiro) | Morales, G. (State University of Northern Rio de Janeiro) | Arica, J. (State University of Northern Rio de Janeiro) | Matias, I. (Universidade Cândido Mendes) | Ferreira, A. S. (Fluminense Federal University) | Carneiro, V. (I-dutto)
Abstract Maintenance shutdown tasks on offshore platforms generate large revenue losses for companies in addition to high costs, partially caused by environmental adverse conditions, distances from workplaces, and large volume of materials. The use of an efficient asset controlling and monitoring system reduces these costs and improves their resource management. This work describes the development of a web/mobile architecture system integrated with radio frequency identification (RFID) transponders for asset tracking in maintenance shutdown processes on offshore platforms. For this study development, we visited an oil and gas company, located in the city of Macaé, Rio de Janeiro, Brazil to analyze its processes. The company was facing problems on its asset management, and tracking material processes. The former takes place in two different sites. It is performed not only on-shore, but also offshore (on oil and gas platforms). Therefore, it was developed a web/mobile system integrated with RFID transponders to tackle these problems. This system enhances efficiency in processes, reduces costs and losses because of production downtime. Its tracking is able to save up to 5.5 (five and a half) days at the laydown yard and approximately 7 (seven) days on the platform. Besides that, it ensures greater assertiveness, thus decreasing the level of materials’ replacement in the tasks, which was one of the main causes for delays in these processes. Other results are related to its managerial processes. They became automated once the RFID system integrates data in real time, and all the items from tasks defined as priorities were identified. The experimented efficiency suggests to use open source tools to reduce the system development costs, and analyze the use of RFID throughout the oil and gas supply chain, as well as studying other applications and systems in different supply chains, focusing on ways to optimize costs for the company. Additionally, it enabled the monitoring of assets and processes throughout the supply chain, besides providing information and knowledge for companies.
- South America > Brazil > Rio de Janeiro > Rio de Janeiro (0.25)
- South America > Brazil > Rio de Janeiro > Macaé (0.25)
There are many physical and financial factors that determine the optimum power generation solution on an Offshore installation - space requirements, weight, reliability, and maintenance requirements to name a few. On top of these factors, environmental impacts must be considered, such as emissions of Nitrous Oxides (NOx) and Carbon Dioxide (CO2), and visible pollution like flaring. Whereas in ‘conventional’ offshore oilfields, there is usually associated gas available to provide the fuel for power generation, Heavy Oilfields provide an additional challenge: they tend to be gas deficient, with insufficient associated gas over field life to fully fuel a power plant. This requires the import of fuel, such as diesel or Heavy Fuel Oil, as these are easily transportable and storable, but importing fuels, and especially premium refined liquid fuels, increases operational costs. Therefore it may be necessary to look at using the produced crude oil itself as the fuel for power generation, and this in itself requires careful consideration by the providers of the different potential power generation technologies. Liquid fuels also produce more NOx when burned, and are more carbon intensive than most gas fuels, increasing CO2 emissions. Heavy oil facilities usually need more heat for production and processing purposes than lighter crude oils, requiring combustion of more fuel to provide the process heat required and increasing CO2 emissions still further. This paper looks at the types of liquid fuels, especially crude oil, and alternative power generation technologies that can be considered, and the potential advantages and disadvantages of these technologies in an Offshore application. It also looks at ways of reducing combustion emissions such as NOx and using Cogeneration as a means of reducing CO2 emissions by maximising overall energy efficiency.
- South America > Brazil (0.46)
- Europe > Norway (0.28)
- Energy > Power Industry (1.00)
- Energy > Oil & Gas > Upstream (1.00)