The objective of the present study was to evaluate the corrosion properties of carbon steel in supercritical carbon dioxide (CO 2 )/brine mixtures related to the deep water oil production development. Corrosion tests were performed in 25 wt% sodium chloride (NaCl) solution under different CO 2 partial pressures (4,8, 12 MPa) and temperatures (65°C, 90°C). Corrosion behavior of carbon steel was evaluated using electrochemical methods (linear polarization resistance [LPR] and electrochemical impedance spectroscopy [EIS]), weight-loss measurements, and surface analytical techniques (scanning electron microscopy [SEM], energy-dispersive x-ray spectroscopy [EDS], x-ray diffraction [XRD], and infinite focus microscopy [IFM]). The corrosion rates measured at 65°C showed a high corrosion rate (~10 mm/y) and a slight difference with pressure. Under these conditions, the sample surface was locally covered by iron carbide (Fe 3 C), which is porous and non-protective. However, the corrosion rates measured at 90°C increased with time at the initial period of the test and decreased to a very low value (~0.05 mm/y) due to the formation of protective iron carbonate (FeCO 3 ) layer regardless the CO 2 partial pressure.
This paper presents the experience brought from the oil-water subsea separatorproject developed for the Marlim field, known as SSAO Marlim. Here, it will beaddressed the inherent arising challenges from a project of a subsea separationequipment, from the subsea mechanical design perspective, with special focus tothe additional requirements to the normally presented in conventional subseaequipment for oil and gas production. It will be part of the discussion the architecture selected for the system andthe main challenges imposed by:–Separation process (gas-liquid, liquid-liquid and sand removal system);–Requirements for modularization, installation and retrieval of subseacomponents;–Installation concept. Introduction The oil-water subsea separator is installed in a water depth of approximately870m in the Marlim field, located in the Campos basin, Brazil. The subseaseparation station has an envelope of 29m length, 10.8m width, 8.4m height andan overall assembly weight in-air of 392ton, and it will receive productionfrom selected well, separate produced water from oil and sand and re-inject itinto Marlim production reservoir via a centrifugal pump. The water separationhappens into a Pipe SeparatorTM based on a gravitational concept, while waterpolishment to meet quality requirements, i.e. reduce oil content in water toacceptable levels for the re-injection into reservoir, is performed by cyclonicequipment. The equipment also has a sand management system which the main aimis to minimize the operational impact induced by solids production. Figure 1 illustrates the oil-water subsea separation system of Marlim.
Deep water oil production tubing materials are exposed to high carbon dioxide (CO 2 ) pressure and temperature conditions that can affect the corrosion performance of such materials. The present study evaluated the corrosion behavior of carbon steel exposed to supercritical CO 2 /oil/brine mixtures at different water cuts (0, 30, 50, 70, and 100%), CO 2 partial pressures (8 MPa and 12 MPa), and temperatures (65°C and 90°C) in a flowing 25 wt% sodium chloride (NaCl) solution. Corrosion behavior of carbon steel was evaluated by using electrical resistance (ER) measurements, weight-loss measurements, and surface analytical techniques (scanning electron microscopy [SEM] and energy-dispersive x-ray spectroscopy [EDS]). The corrosion rates of carbon steel increased with increasing water cut. There was no indication of corrosion attack with 0% water cut. At lower water cuts (30% and 50%), the steel surface was covered by iron carbonate (FeCO 3 ), while iron carbide (Fe 3 C) was present on the steel surface at higher water cuts (70% and 100%) with very high corrosion rates. In addition, the presence of flow prevented the formation of protective FeCO 3 at high water cut conditions.
This paper presents the Albacora field Subsea Raw Water Injection (SRWI) systems. Application of SRWI involves some challenges, which demand a detailed and systematic analysis in order to evaluate the technical feasibility and establish the requirements to implement this solution. This paper describes the evaluation process carried out and details the adopted solutions. Furthermore, the system installation and operation are presented. The Albacora field is a mature field located at Campos Basin in water depths between 250 and 1100 meters. In order to increase the oil recovery, its reservoirs are requiring a significant amount of water injection, what was not considered in the initial phases of the Albacora field development project. Technical and economical constraints do not allow the use of conventional seawater injection plants, since current production units have no available area to implement a conventional water injection system. The selected alternative to overcome these constraints was the SRWI technology, by which seawater is injected in the reservoir with a minimum treatment, using mainly pieces of equipment installed at seabed. The feasibility analysis involved studies of the seawater compatibility with the reservoir rock and fluids, microbiological control, corrosion, etc. The solution was specified based on these studies and included subsea pumps, back-flushing filters, well components and topside facilities. In order to achieve required seawater flow rates, the adopted solution considered the use of three subsea injection systems, injecting around 16,500 m3/day in seven wells. Waterflooding is still the most common method used worldwide for improving oil recovery. The SRWI technology can be an important alternative to inject seawater where it is not possible to use conventional systems, mainly in mature fields. The SRWI is expected to generate large economical and technical benefits to the Albacora project. Introduction Water injection has a high economical impact in offshore projects, because it affects directly the recovery factor and the production flow rates. Hence, the development of technologies that overcome technical or economical problems to guarantee adequate water injection flow rates in offshore fields is critical. In some offshore fields, mainly mature fields, the impact of the conventional technologies in the topside facilities can be a constraint to increase or enable seawater injection. These conventional systems require the installation of too many pieces of equipment at the production units, demanding large areas that sometimes are not available. Other restrictions could occur, like load limitations, FPSO swivel constraints etc. One alternative to overcome these problems is the Subsea Raw Water Injection (SRWI) technology, by which most of the system is installed at seabed and seawater is injected with minimum treatment, leading to a much lower impact in the topside facilities. The SRWI alternative involves technical challenges, such as: seawater compatibility with the reservoir rock and fluids, microbiological control, corrosion, water properties, reliability of the subsea equipment and power, which limit the use of this technology in some scenarios. PETROBRAS established a R&D project to evaluate and develop this technology, involving technical feasibility studies, evaluation of scenarios and preliminary specifications. During this project, Albacora field reservoir studies indicated the need of large amounts of water injection and SRWI became the only economically feasible alternative identified to address this demand.
Summary Tanks used to store produced water on floating production, storage, and offloading units (FPSOs) are extremely susceptible to generation of high hydrogen sulfide (H2S) levels because of the activity of sulfate-reducing bacteria (SRB). The FPSOs operated by Petrobras in the Campos basin, offshore Brazil, all contain slop-water tanks, while some also have upstream oil/water-separation tankage. Slop water, including produced water, ballast water from oil cargo ships, and deck water, contains SRB and their nutrients required for generating H2S. Additionally, solids accumulations at the tank bottoms provide an excellent environment for microbial growth. A 2002 field trial on an FPSO confirmed the viability of combined batch treatments using anthraquinone (AQ) and a THPS blend and their effectiveness in controlling H2S biogeneration better than previous treatment programs. AQ, a nontoxic SRB inhibitor, and tetrakishydroxymethyl phosphonium sulfate proprietary blend (THPS), an oilfield biocide, act synergistically to provide effective control of H2S biogeneration in this environment. The combined-chemical treatment strategy has now been implemented successfully on six Petrobras FPSOs. Flexibility has been important in developing the treatment programs because operating parameters are different for each FPSO and change with increased water-production rates. Options include the ability to inject the chemicals continuously or batchwise at different locations and to alter the volumes and ratios of chemicals for optimizing control over H2S and corrosion. This paper describes the individual FPSO water-flow and water-storage systems and discusses the customized chemical treatment programs. Included are field H2S data showing the evolution of the programs as they are being continually adjusted to optimize control of H2S generation and cost-effectiveness. Also included are results of laboratory microbial studies showing the synergy of anthraquinone and THPS and of corrosion studies that have impacted the direction of usage of these chemicals. With more than 100 FPSOs operating worldwide, the treatment program described can significantly affect the safety and environmental aspects of processing water containing SRB. Introduction The use of FPSOs and floating storage and offloading units (FSOs) to produce oil or to process oil and water associated with offshore production has increased to approximately 106 units currently in operation worldwide (Offshore 2006). These FPSOs and FSOs are ships containing multiple tanks for separating oil and water, storing oil before offloading into tankers, and processing waters. Produced water typically flows into slop tanks, where it may also combine with drainage water from decks or ballast water from cargo ships. Slop tanks are in many cases the final separation stage in which residual entrained oil is removed from the water before its discharge to the sea, offloading, or reinjection. Environmental concerns dictate that total oil and grease (TOG) is a crucial water-quality criterion before discharge, but the level of H2S is also critical because of its high toxicity and corrosivity to carbon steel. Oil/water separators and slop-water storage tanks are prime locations for activity of SRB and the subsequent generation of high levels of H2S. SRB are particularly abundant in most oilfield waters, including seawater. The slop waters also typically contain all the nutrients required by the SRB for their growth and dissimilatory respiration, reducing sulfate to sulfide. Environmental conditions in the slop-water tanks, especially the presence of sludge and solids deposits at the bottom of the tanks, are quite favorable for these anaerobic bacteria to form biofilms. These solids are also protective to the SRB and impede the action of chemical biocide treatments for controlling bioactivity. Health, safety, and environmental aspects associated with the presence of the toxic gas on offshore structures make it necessary to implement effective SRB- and H2S-control procedures while still maintaining compliant water for discharge. Petrobras currently operates 10 FPSOs and FSOs in the Campos basin, approximately 180 km northeast of Rio de Janeiro. The FPSOs are located in water depths from 160 to 1240 m. Some units have production facilities (FPSOs), while others (FSOs) only receive produced oil and water from other platforms. All have slop-water tanks with varying degrees of SRB activity, depending on the producing-fluids composition and reservoir characteristics. The fields subjected to seawater injection are prone to biogenic H2S generation, and those with low-salinity formation water and low reservoir temperature tend to be the most susceptible. As described previously, the dual treatment program of a biocide, THPS, and a biostat, AQ, was quite successful at controlling H2S biogeneration on one of the Petrobras FPSOs (Penkala et al. 2004). This dual treatment program has been implemented subsequently on five additional FPSOs, as its effectiveness has continued to be validated under the varying water and SRB conditions on each unit. This paper discusses the progression of the program as it has been customized and continually adjusted by each FPSO to optimize the control of H2S generation and cost-effectiveness. Also presented are laboratory data showing the synergy of THPS and AQ in dual treatments, as well as results from corrosion studies with the two chemicals.
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