This article, written by Special Publications Editor Adam Wilson, contains highlights of paper OTC 27757, “Effect of Hydrodynamic Parameters on Wax Mass Density: Scaleup From Laboratory Flow Loop to Crude Production Pipelines,” by N. Daraboina, SPE, J. Agarwal, SPE, S. Ravichandran, SPE, and C. Sarica, SPE, The University of Tulsa, prepared for the 2017 Offshore Technology Conference, Houston, 1–4 May. The paper has not been peer reviewed. Copyright 2017 Offshore Technology Conference. Reproduced by permission.
Oil- and gas-production pipelines typically operate at high Reynolds number and low wall shear stress. Current wax-deposition-prediction models, however, were developed on the basis of laboratory flow-loop experimental data obtained at high shear stress and low Reynolds number. In this study, the effects of the hydrodynamic parameters are decoupled with specially designed flow-loop experiments. The results enhance understanding of the deposition behavior at various hydrodynamic conditions and aid in scaling up from laboratory to field conditions.
Subsea production faces both fluid- and flow-based challenges, which eventually can lead to shutdowns, safety issues, and intermittency in production. Among these challenges, the deposition of paraffin, or wax, in the pipelines has gained attention as a flow-assurance problem. The severity can be realized in terms of lost production from reduced flow area, large changes in the pressure drops across pipelines, and changes in fluid properties such as an increase in viscosity of oil with wax precipitation. Accuracy in determining wax buildup across a pipe is critical for designing and applying remediation techniques. For example, accurate prediction of deposition parameters is necessary to manage the pigging process in production lines—including pigging frequencies and mechanical designs of pigs—and treatment of deposits with inhibitors. The assessment of the overall mass flux from the bulk to the interface is a prerequisite for accurate prediction of wax deposition, followed by the prediction of aging and growth individually of the deposit.
The existing models predicting paraffin deposition use nonrepresentative parameters that cannot be scaled up to field conditions because of the empiricism associated with the parameters. The failure of the parameters may partly be because of the application of incorrect variables used in development of empirical relationships for the parameters. These models show inconsistency in predicting field data. Selecting the correct hydrodynamic parameter for scaleup studies, therefore, is important.
Fluid Characterization. The experimental fluids used in this study are laboratory-synthesized model oil containing 5 wt% food-grade wax and Garden Banks condensate.
Experimental Facility. A small-scale facility is used to conduct flow-loop deposition experiments. This facility has three 8-ft pipeline test sections with different diameters. This enables effectively decoupling the effect of Reynolds number and shear stress at the wall on wax deposition. The test sections are configured as pipe-in-pipe to allow for countercurrent flow of oil and glycol.
Direct time integration is a widely-used method for the analysis of loads and motions of mooring and floating systems. Nonlinear and transient effects can be easily accounted for in time domain analyses but it is a computationally expensive method, especially for explicit solvers which are limited by the timestep size to meet numerical stability requirements. There is potential in using multirate time to reduce computation times. This paper presents the development and evaluation of a multirate timestepping algorithm based on the Modified Euler integration method for the solution of mooring dynamics. The temporal synchronization as well as spatial boundary conditions needed for coupling the partitioned line segments with different spatial discretizations are presented. The stability parameters and gains in computational efficiency of the method are evaluated with numerical experiments based on a simple test case.
Sand production and erosion can present rigorous challenges during the design and production phases of the subsea oil and gas production system and lead to significant increase in the CAPEX and OPEX. Thus, the accurate prediction of the erosion rates, location of erosion hotspots and expected sand accumulation zones in production system is a key task during the design, as well as for the development of sand monitoring systems used during the production phase.
In the recent years, simulation of multiphase flows including sand management and erosion prediction has become a powerful engineering tool in the oil and gas industry. There have been many significant improvements to the modelling approaches including more details of the flow physics, rapid development of the computational resources, and the adaption of modelling methodologies from other industries such as aviation and automobile. However, the generic simulation models and tools must be validated and tested before they can be used in the design, product development or monitoring systems of the oil and gas specific applications. The erosion production models and tools are applied to conduct virtual experiments to help designing the the production system during the project design phase. In addition, high fidelity flow and erosion simulations can minimize the cost of the production system design and operation optimization as they enable sensitivity studies for large number of design variations and production condition sets – provided they present an industrial application in terms of short simulation runtime and low resource effort.
Recently, GE Oil & Gas examinend the validity of existing erosion prediction correlations and modelling approaches in commercial Computational Fluid Dynamics (CFD) software. Sand particles transport and erosion laboratory experiments – on different materials as well as for subsea production system like flow loop configurations with test conditions close to the actual operation conditions – were performed to gather test data that can be used for the validation of the numerical simulations.
The objective of this paper is to present part of the effort, focusing on the geometry and piping elements’ arrangements (bends arrangements) impact on the erosion rates and erosion hotspot locations, the validation results of 1D tools and 3D CFD erosion prediction models and the comparison to the test data. Furthermore, future development required to enhance the accuracy of the modelling results and the uncertainties are addressed.
The major challenges to all methods are 1) erosion prediction for very small sand (<50 µm), 2) lack of quality field data for validation and improvement, 3) high level of uncertainty due to the complexity of the erosion process.
Significant inconsistency between the erosion predicted by different models was the driver for the effort. Choosing one or the other in certain applications is not always obvious and can be difficult to justify, yet they can give very different results. The community needs to fully understand the situation and look for a solution.
The oil industry has faced growing demand for subsea facilities to enable the development of ultra deepwater oil fields. The use of manifold is an alternative widely considered in subsea arrangements. In order to apply this alternative, it is necessary to follow a chain of project that demands special care since its manufacture, installation, commissioning, productive life and possible demobilization, being able to culminate with the removal of equipment from the location. These equipments, sometimes weighing a few hundred tons, require special attention during planning the installation. Thus, this paper proposes to present the challenges faced in the planning and installation of subsea equipments in deepwater, the evolution of the manifold installation techniques at Petrobras, as well as present the main installation methods currently used in Pre-Salt fields and new techniques in development for the installation of large subsea equipments.
de Abreu Campos, Nathalia (PETROBRAS) | da Silva Faria, Marcílio José (PETROBRAS) | de Moraes Cruz, Rafael Oscar (PETROBRAS) | de Almeida, Amaya Caldas Villar (PETROBRAS) | Rebeschini, Edson José (PETROBRAS) | Vaz, Henrique Paes (PETROBRAS) | João, Leonardo Villain (PETROBRAS) | Rosa, Marcelo Becher (PETROBRAS) | da Fonseca, Tiago Cardoso (PETROBRAS)
This article presents the successful history of Lula Alto Project, one of the development modules of Lula giant field, located in Santos Basin pre-salt at southeast Brazil at a 2,120 meters water depth. The project is currently producing at its maximum oil capacity, considering operational performance, achieved only 9 months from first oil. This is the fifth module of Lula field, which modular development allowed drainage plan and subsea layout optimization.
The article will present the reservoir conceptual model, drainage plan optimization, information acquisition strategy and modular development insights; the subsea layout optimization that led to a minimum flowline length per well; twin FPSO construction strategy; project development and fast ramp-up and the challenges faced during the first year of production. It will also address integrity and maintenance management, aiming a secure and sustainable operation, and well construction highlights.
The leased FPSO Cidade de Maricá initiated production in February 2016, and the project strategy was to carbon copy FPSO Cidade de Ilhabela engineering (this FPSO is also producing in pre-salt), reducing design costs and schedule. Construction phase strategy was to build two identical FPSO's in parallel, FPSO's Cidade de Maricá and Cidade de Saquarema, with a planned 2 months schedule delivery gap. Suppliers and construction sites were the same, allowing cost reduction, construction risks mitigation and supply chain optimization. After one year of production, many challenges had to be surpassed, and all lessons learned were important for a solid ramp-up achievement and sustainable peak production.
Three years of depressed oil prices have had a significant effect on the market for producing technologies, such as subsea, which had become dependent on the 2014 price levels to remain profitable. In addition to lower oil prices, increasing production costs because of the more-challenging project conditions of deeper water, longer tieback distances, and harsher reservoir properties have intensified this effect on both operators and equipment suppliers. Today, subsea processing offers the industry a wide range of technology-ready tools that can improve the economics of subsea field development for both brownfield and greenfield applications.
Harry Barnum has been named a principal consultant and regulatory manager at InterAct. Barnum has more than 30 years' experience in the oil and gas industry, having managed all aspects of oilfield development including reservoir analysis, drilling and facility optimization, waterflood and steamflood injection program design, property valuation, regulatory and safety compliance, training, mapping, and field engineering. He has managed both onshore and offshore production facilities and has written and implemented spill response programs. He has also completed environmental assessments and managed numerous remediation programs gaining regulatory site closure.
Starting up a subsea production system for large offshore developments is a time-consuming task that can take multiple hours or days. The startup is particularly inefficient during an unplanned shutdown, where the operator may have a threshold time (e.g., 4–6 hours) to fix the problem and startup the production system, before having to preserve the field.
The workflow discussed in this paper aims to determine and reduce the startup time of a subsea production system (SPS). At the center of the workflow, a dynamic integrated model is used to accurately assess and effectively adjust scheduled startup time of the SPS. The integrated model evaluates the dynamic simulation response of a large field startup by integrating a reservoir and gathering network model. The overall workflow incorporates subsurface simulation model, equipment design, field layout design, control systems, and system constraints to create a complete field architecture capable of handling quick, efficient field startups throughout the field life.
The integrated workflow presented in this paper captures a full dynamic response, from the reservoir to the topside. Among other things, a full reservoir model has been integrated with a full dynamic network model that allows for startup evaluation and adjustment to be performed at different points throughout the field life.
With the improvement of Smoothed Particle Hydrodynamic (SPH), it has become one of most vigorous methods for breaking wave simulation. Recently we have developed an improved SPH method for simulating violent flow and two bodies interaction. The main features of this new method include the incompressible SPH method based the pressure Poisson equation, and it also gives a new scheme to deal with moving boundary. In this paper, this improved method will be applied for simulating waves and its impact with single floating body and two floating bodies, and the results are compared with experiment measurements.
The smoothed Particle Hydrodynamics (SPH) method is a meshless, purely Lagrangian technique which was originally developed by Lucy (1977), and Monaghan and Gingold (1977). While the WCSPH scheme has been successfully used for violent free surface flow, the stiff equation of state can result in large unphysical pressure fluctuations. These spurious oscillations in the pressure field can be mitigated by reducing the sound speed and relaxing the system at the same time. As a remedy for large unphysical pressure oscillations, Colagrossi and Landrini (2003) corrected the density calculation by renormalizing the density using Moving Least Square (MLS) density correction. They showed that, the correction improves mass area density consistency and also filters out pressure oscillations. They also found out that the density re-initialization procedure is beneficial with respect to energy conservation when it is used along with artificial viscosity. Molteni and Colagrossi (2009) have proposed a δ -SPH scheme by modifying the SPH equations and adding a proper artificial diffusive into the continuity equation in order to remove the spurious numerical high-frequency oscillations in the pressure field. However, these WCSPH issues need a very small time-step in order to resolve the artificial compressible equation. Another important improvement of pressure noisy is the scheme of weakly compressible SPH based on Riemann solver. Monaghan (1997) showed that the artificial viscosity is analogous to the terms constructed from signal velocities and jumps in variables across characteristics in the Riemann problem. Parchikov and Stanislav (2002) proposed a modified SPH method using a first order approximation of the acoustic Riemann solver, which does not require an artificial viscosity term for dissipation. Guo et al (2012) introduced the re-normalized approximation to the Riemann solver. According to the form of SPH based on Riemann solver, which is not uniform and some numerical techniques are still in open for discussion, different researchers may introduce different expressions, so SPH based on Riemann solver is not considered in this paper.