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Collaborating Authors
North Sea
The availability of some processing spare capacity in offshore facilities, during its operational life, is an expected event. At some point in time, it is also expected that some fields may share their assets, in order to enhance its economic value. Asset Sharing Agreements are efficient tools for those purposes. However, taxation and fiscal regime in Brazil does not promote a friendly framework for this initiative. This article aims to discuss some key issues that regulatory agents shall address for adequating Brazilian legal framework to international oil industry standards.
- South America > Brazil (1.00)
- North America > United States > Texas > Kleberg County (0.25)
- North America > United States > Texas > Chambers County (0.25)
- South America > Brazil > Campos Basin (0.99)
- South America > Brazil > Espírito Santo > Espirito Santo Basin (0.98)
- North America > United States > Gulf of Mexico > Central GOM > West Gulf Coast Tertiary Basin > Walker Ridge > Cascade Prospect > Block 250 > Cascade-Chinook Field (0.94)
- (11 more...)
Abstract New technologies that contribute to enhanced production in ultralong tiebacks have recently been developed. These new developments include higher differential pressure in multiphase pumps and compressors, mechanical designs for high pressures and temperatures, and power systems suited for ultralong tiebacks. When developing new, cost-efficient boosting technology for long subsea tiebacks and deep water, a system approach is important. This includes power systems, installation methods, maintenance, reliability, and condition monitoring. The new technologies described have been developed based on operational experience and physical theory combined with practical experiments and validation, both scaled and full size. The importance of developing simple and reliable solutions in facilities that enables comprehensive experimenting and testing is also explained. Today’s oil and gas price level also requires cost-efficient solutions, and the paper explains how this can be obtained through standardization and modularization. The first pump systems that are able to provide a more-than 200-bar differential pressure are already developed, qualified, and put in operation. A game-changing multiphase gas compressor technology that provides differential pressure up to 55 bar has also been built, tested, and verified. In parallel with these developments, subsea power systems have been further developed so that they can be used for step-outs longer than 200 km. Recently, a multiphase pumping station designed for 2,500-m water depth and 15,000-psi design pressure was installed and set in operation in the Gulf of Mexico. All of this contributes to enhanced production and lower field developments costs in subsea environments and provides a platform for further technology developments that can potentially make extremely remote subsea field developments economically attractive. This paper presents new technology related to multiphase pumping and compression and a system approach that can make production from remote and deepwater subsea fields more capital efficient.
- North America > United States > Texas (0.31)
- Oceania > Australia > Western Australia (0.29)
- North America > United States > Gulf of Mexico > Central GOM (0.29)
- Oceania > Australia > Western Australia > North West Shelf > Carnarvon Basin > Exmouth Basin > PL WA-59-L > EnField Field (0.99)
- Oceania > Australia > Western Australia > North West Shelf > Carnarvon Basin > Exmouth Basin > PL WA-28-L > WA-28-L > Vincent Field > Lower Barrow Formation (0.99)
- Oceania > Australia > Western Australia > North West Shelf > Carnarvon Basin > Exmouth Basin > PL WA-28-L > WA-271-P > Vincent Field > Lower Barrow Formation (0.99)
- (79 more...)
Abstract There are several methodologies that use 4D seismic (4DS) information as deterministic dynamic observed data to improve the accuracy of reservoir simulation models. However, 4DS data also have uncertainties due to errors caused by resolution, acquisition, processing and interpretation. Deterministic 4DS information does not consider these uncertainties properly. Thus, the objective of this work is to evaluate the application of a methodology that incorporates 4DS and simulation data probabilistically, considering uncertainties from both data sets. Through the combination of uncertain reservoir parameters, multiple simulation models are generated/simulated, providing multiple pressure change (ΔpSIM) maps. In this study, the available 4DS data are multiple pressure change (Δp4DS) maps yielded from a probabilistic seismic inversion. We first transfer the Δp4DS maps to the simulation scale and then, for each reservoir position, we build two probabilistic density functions: (1) PDFSIM using ΔpSIM maps and (2) PDF4DS from Δp4DS maps. We then compare PDFSIM and PDF4DS, establishing which one is the most precise in each reservoir position, and use this information to select the most precise ΔpSIM and ΔpSEIS maps. We used a synthetic reservoir with moderate complexity, eight predominant uncertainties (such as permeability and porosity), 11 producers and eight water injectors. Two sets of ΔpSIM were studied: (a) 500 ΔpSIM maps generated from 500 simulation models at the beginning of a probabilistic history-matching procedure using wells and (b) 97 ΔpSIM maps from history-matched models using well production data. Two sets of 4DS data were considered: (c) 125 Δp4DS maps yielded from a probabilistic inversion considering reservoir uncertainties and noiseless synthetic seismic data (d) 500 Δp4DS maps from a probabilistic inversion considering reservoir uncertainties and noisy synthetic seismic, representing a more realistic 4DS data. Using as input data (a) and (c), we identified positions where Δp4DS maps were more precise. We then selected the ΔpSIM maps using Δp4DS values at these positions. As result, selected ΔpSIM maps presented more precise estimates of pressure than the initial ΔpSIM maps. Applying (a) and (d), more precise estimates of ΔpSIM were also obtained. Using (b) and (c+d), we identified, through our methodology, reservoir positions where simulation data are more precise than 4DS data. The selected Δp4DS maps using ΔpSIM values presented more accurate and precise estimates then the initial Δp4DS maps. The main contribution of the work was to apply a methodology incorporating simulation and 4DS data, considering uncertainties from both. Applying the studied methodology, we can use seismic information to update simulation models, as well as simulation data to reinterpret 4DS data (employment of engineering data to constrain 4DS).
- South America > Brazil (0.46)
- North America > United States (0.46)
- Europe > United Kingdom (0.28)
- (2 more...)
- Europe > United Kingdom > North Sea > Northern North Sea > East Shetland Basin > Block 211/25 > Statfjord Field > Statfjord Group (0.99)
- Europe > United Kingdom > North Sea > Northern North Sea > East Shetland Basin > Block 211/25 > Statfjord Field > Cook Formation (0.99)
- Europe > United Kingdom > North Sea > Northern North Sea > East Shetland Basin > Block 211/25 > Statfjord Field > Brent Group (0.99)
- (10 more...)
- Reservoir Description and Dynamics > Reservoir Simulation > History matching (1.00)
- Reservoir Description and Dynamics > Reservoir Simulation > Evaluation of uncertainties (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Seismic processing and interpretation (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Four-dimensional and four-component seismic (1.00)
Intelligent System for Start-Up and Anti-Slug Control of a Petroleum Offshore Platform
Campos, Mario C. M. M. (Petrobras) | Ribeiro, Leonardo D. (Petrobras) | Diehl, Fabio C. (Petrobras) | Moreira, Cristiano A. (Petrobras) | Bombardelli, Douglas (Petrobras) | Carelli, Alain C. (Petrobras) | Junior, Gilberto M. J. (Petrobras) | Pinto, Sergio F. (Petrobras) | Quaresma, Bernardo (PUC-Rio/Tecgraf)
Abstract It is difficult to control and to manage wells’ start-up in offshore platforms. In order to solve this problem an intelligent system can play an important role, since available qualitative operator and design knowledge can be easily implemented to assist the operator during wells’ start-up. This paper describes the integration of an expert system associated with anti-slug control for well start-up. The intelligent system has many heuristic rules to implement the automation of the start-up procedures, like the opening choke valve while simultaneously respecting many constraints. Severe slugging flow regimes are one of the major disturbances for the operation of offshore production platforms, and can cause many unplanned shutdowns. Therefore, it’s important to combine start-up intelligent system with an anti-slug advanced control module for each well. The benefits are associated to reducing possibility of unplanned shutdowns during well start-up operational procedures, decreasing operators’ stress and also helping to minimizing impacts to the environment. A prototype was implemented in one platform with good results for a safe and efficient wells start-up procedure. This paper will present the development and results of this intelligent system for wells’ start-up and anti-slug control for offshore platforms.
- South America > Brazil (1.00)
- North America > United States > Texas (0.47)
- South America > Brazil > Campos Basin (0.99)
- Europe > United Kingdom > North Sea > Southern North Sea > Southern Gas Basin > Silver Pit Basin > Block 49/30c > Davy Fields > Brown Field > Rotliegend Formation (0.99)
- Europe > Norway > North Sea > Northern North Sea > Bjørgvin Arch > North Viking Graben > PL055 > Block 31/7 > Brage Field > Statfjord Formation (0.99)
- (29 more...)
Abstract The Peregrino Field is an accumulation of 13-16° API oil in the Carapebus Formation in the Campos Basin and is thereby one of the heaviest oil offshore developments in Brazil. The field was discovered in 1994 and in 2007 Statoil became a Peregrino partner followed by Peregrino operatorship in 2008. The field has been in production since 2011 by using two well head drilling platforms and one FPSO in water depth ranging between 95 to 135 m. There are 45 production and injection wells drilled so far and 15 remaining slots on the platforms. The Peregrino recovery mechanism is mainly based on reservoir depletion and rock compaction combined with aquifer pressure support and produced water reinjection in the water and oil zones. The viscosity difference between oil and water at Peregrino gives an unfavorable mobility ratio, and water flows with a higher velocity than the oil. Any means to limit the water flow from the wells may enable an optimization of oil production. In 2013, a technology qualification program was conducted to qualify both Inflow Control Devices (ICD) and Autonomous Inflow Control Devices (AICD) technologies for use at Peregrino. Since then 2 wells have been equipped with ICDs and 7 with AICDs. The production experience from those ICD/AICD wells shows that the device is best suited in areas with good pressure support, high productivity index (PI) and heterogeneous reservoir. The paper will cover a comprehensive evaluation done for the ICD/AICD wells in Peregrino focusing on subsurface data challenges and performance predictions.
- South America > Brazil > Rio de Janeiro > South Atlantic Ocean > Campos Basin > Block BM-C-7 > Peregrino Heavy Field (0.99)
- South America > Brazil > Rio de Janeiro > South Atlantic Ocean > Campos Basin > Block BM-C-47 > Peregrino Heavy Field (0.99)
- South America > Brazil > Campos Basin (0.99)
- (12 more...)
Abstract Control system failures in subsea operations are a leading cause of Blowout Preventer (BOP) down-time. The cost of these failures can increase exponentially with water depth. Legacy BOP control systems are based on 90-year-old hydraulics technology and have been stretched to cope with new regulatory requirements and harsher environments. The industry has responded to these design requirements by increasing component sizes, weights, and system complexities. These adaptations have resulted in unintended consequences, such as reduced reliability and an increase in wellhead loading. As subsea operations move into deeper water and wellhead pressures increase above 15,000 psi, legacy control systems may have reached their design limit. This paper introduces a new concept of an all-electric BOP, a game-changing technology that will not only negate these issues, but also improve the safety, efficiency, reliability, and functionality of subsea BOP control systems.
- North America (1.00)
- Europe > Norway (0.93)
- Europe > United Kingdom > North Sea (0.46)
- Europe > United Kingdom > North Sea > Northern North Sea > East Shetland Basin > Block 211/7a > Magnus Field > Kimmeridge Formation > Magnus Formation (0.99)
- Europe > United Kingdom > North Sea > Northern North Sea > East Shetland Basin > Block 211/7a > Magnus Field > Kimmeridge Formation > Lower Kimmeridge Clay Formation (0.99)
- Europe > United Kingdom > North Sea > Northern North Sea > East Shetland Basin > Block 211/12a > Magnus Field > Kimmeridge Formation > Magnus Formation (0.99)
- (55 more...)
Advanced Control for Gas-Lift Well Optimization
Campos, Mario C M M (PETROBRAS/CENPES) | Lima, Marcelo L (PETROBRAS/CENPES) | Teixeira, Alex F (PETROBRAS/CENPES) | Moreira, Cristiano A. (PETROBRAS/UO-RIO) | Stender, Alberto S (PETROBRAS/UO-RIO) | Von Meien, Oscar F. (PETROBRAS/SUP) | Quaresma, Bernardo (PUC-Rio/Tecgraf)
Abstract The search for improvements in the production efficiency is one of the main challenges for the production engineers responsible for an asset, mainly at moments of low prices and very strict regulations for safety, environment and quality of products. Another point is that offshore plants are becoming more complex, so advanced control systems can support the operators and play an important role to improve stability and profitability. This paper will present an advanced control algorithm for gas-lift optimization of offshore wells that aims to increase oil production. It will also show and discuss some results of the implementations of this real time advanced control system in two offshore platforms, emphasizing the economic gains and critical points to maintain this controller running with a good performance.
- South America > Brazil > Campos Basin (0.99)
- Europe > Norway > North Sea > Northern North Sea > Bjørgvin Arch > North Viking Graben > PL055 > Block 31/7 > Brage Field > Statfjord Formation (0.99)
- Europe > Norway > North Sea > Northern North Sea > Bjørgvin Arch > North Viking Graben > PL055 > Block 31/7 > Brage Field > Sognefjord Formation (0.99)
- (28 more...)
New-Generation, Circumferential Ultrasonic Cement-Evaluation Tool for Thick Casings: Case Study in Ultradeepwater Well
Acosta, J. (Halliburton) | Barroso, M. (Halliburton) | Mandal, B. (Halliburton) | Soares, D. (Halliburton) | Milankovic, A. (Halliburton) | Lima, L. (Petrobras) | Piedade, T. (Petrobras)
Abstract This paper describes the deployment of a new circumferential ultrasonic tool for cement evaluation used in a thick-casing environment. The operation was performed in a deepwater well, where massive loads often require heavier linear-weight casings with thicknesses greater than 1.0 in. A new-generation, circumferential, ultrasonic cement-evaluation tool was run in combination with a cement bond-log (CBL) tool to evaluate a primary cementing operation and assure zonal isolation in an ultradeepwater well with 10 3/4-in. casing set in the 14 3/4-in. hole section. Casings with thicknesses greater than 1.0 in. are outside the operating range of current circumferential ultrasonic tools. The improvement features, main specifications, and measurement physics comparing the new tool with previous-generation technology are presented. The operation was performed in a well containing two sizes of 10 3/4-in. casing in the same casing string. Both 85.3 lbm/ft (0.8-in. thick) and 109.0 lbm/ft (1.0-in. thick) casing sections were present and evaluated in the same pass. The sonic/circumferential ultrasonic combination was able to effectively evaluate the quality of the primary cementing operation behind both casing weights, as well as positively detect the top of cement (TOC). The combination of the ultrasonic tool with traditional bond-log technology provides independent and complementary measurements of cement bond quality. This presented the operator with the ability to radially analyze the zonal isolation using an image map and to identify cement quality issues, such as channeling and the presence of microannuli. In addition, the casing integrity was evaluated in the same pass using the ultrasonic tool. The new ultrasonic tool makes it possible to achieve confirmation of well integrity in complex, deepwater environments, clearly identifying zones ranging from free pipe to fully cemented conditions, including radial mapping. Improvements in the measurement physics enables the analysis of the annulus in cases of heavy, thick-walled tubulars, as well as in the presence of heavier drilling fluids.
- Europe > United Kingdom > North Sea (0.89)
- Europe > Norway > North Sea (0.89)
- Europe > Netherlands > North Sea (0.89)
- (2 more...)
Regulatory constraints governing the discharge of contaminated waste water in offshore operations are increasing across the world. In most regions, contaminant (oil) levels above 30 mg per liter are strictly monitored and regulated to protect our environment. These regulations prohibit disposal of contaminated material offshore, forcing this "slop" water to be transported from the rig to shore for proper treatment and/or disposal. The costs associated with transport, handling, and disposal are incremental to the drilling operations and drive up the cost of the well. These additional rig and logistical operations further expose rig personnel to potential health and safety risks by burdening the crew with additional activity and movement of materials. The intent of this paper is to show the performance capabilities of an innovative waste management system that has been proven capable of reducing the slop water volumes in offshore operations by as much as 80%. A novel waste management system has been developed and designed specifically to reduce the costs associated with offshore waste water management. The technology has been performance tested to prove that it can efficiently remove the contaminants required to allow clean permeate to be discharged to sea. Testing conducted to confirm system capabilities utilized genuine offshore slop water at various levels of contamination. Waste contents tested ranged between 1% and 10% and were comprised of both oil and solids. Performance testing has been successful for over one year with no visible suspended solids detected in the resulting permeate. All concentrations tested showed the quality of permeate produced to be below the 30 mg/liter oil in water threshold, qualifying it for discharge to sea. Additionally, the reliability and maintenance needs of the system were benchmarked to confirm operational efficiency and cost requirements. The system's performance has shown the ability to significantly reduce the volume of waste/slop water that would otherwise have to be transported to shore and treated/disposed of as prescribed by regulatory agencies. The system's ability to remove these contaminants directly results in reductions as high as 80% in the volumes being shipped to shore for treatment and disposal and consequently a significant reduction in disposal and handling costs.
- Water & Waste Management > Water Management > Water Supplies & Services (1.00)
- Energy > Oil & Gas > Upstream (1.00)
The application of advanced control techniques in offshore oil production plants is a challenge. There are many changes in operational points in time, for example, the process is affected by the natural oil well's behavior dynamics. Besides that, limited instrumentation available has to be considered when thinking in oil optimization and control. In order to improve the scenario, taylor-made advanced control modules have been developed for those units. The present article will present development, implementation and results of anti-slug control for four platforms located at Campos and Santos basins. Severe slugging flow regimes are one of the major disturbances for the operation of offshore production platforms. Slugs can occur, for example, in pipeline-riser systems that transport oil and gas mixture from the seabed to the surface and they are characterized by severe flow and pressure oscillations, with moments of high instantaneous liquid or gas flow, which is then followed by moments of almost no flow. This cyclical phenomenon can cause many problems like reduction in process efficiency, and production losses due to many unplanned shutdowns. One of the ways to minimize issues associated with slugs is to use advanced control techniques in wells. These techniques utilize the available measurements, as downhole pressure (PDG) and top side pressures, to define a choke valve position that minimize or even eliminate slug instability. The objective is to have a stable flow together with the maximum possible production rate. One great challenge for this anti-slug control is how to deal with plant nonlinearity, because the process gain of the system changes drastically at different operating conditions. So, we will discuss in this paper different control algorithms to deal with this problem. This paper will present an anti-slug advanced control, which has three subsystems: one responsible to diagnose and identify slugs, considering some pressures patterns; other to control or minimize slugs; and finally one to protect the process plant in case of severe disturbances. Finally, this paper will show and discuss some economic and safety results of the implementations of these anti-slugs advanced control systems in offshore platforms, emphasizing the benefits obtained, which are related with stability, energy efficiency, and profitability due to a important decreasing in unscheduled compressor shutdown events, as well as increasing in operational efficiency. It will be shown that operators have well accepted this system and are maintaining this controller in automatic mode in more than 80% of the operating time.
- Europe > Norway > North Sea > Northern North Sea > Bjørgvin Arch > North Viking Graben > PL055 > Block 31/7 > Brage Field > Statfjord Formation (0.99)
- Europe > Norway > North Sea > Northern North Sea > Bjørgvin Arch > North Viking Graben > PL055 > Block 31/7 > Brage Field > Sognefjord Formation (0.99)
- Europe > Norway > North Sea > Northern North Sea > Bjørgvin Arch > North Viking Graben > PL055 > Block 31/7 > Brage Field > Lista Formation (0.99)
- (28 more...)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring (1.00)
- Facilities Design, Construction and Operation > Pipelines, Flowlines and Risers > Risers (1.00)
- Facilities Design, Construction and Operation > Pipelines, Flowlines and Risers > Pipeline transient behavior (1.00)
- (2 more...)