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Subsea processing and boosting can be key enablers and optimization alternatives for challenging field developments whose benefits increase with water depth, flow rates, and stepouts. This paper summary focuses upon reporting new research-and-development (R&D) initiatives related to subsea processing and boosting offshore Brazil. In the initial exploitation stages of offshore oil and gas fields, the main concern involves the initial investment to construct the production units, drill the wells, and install all equipment necessary for production. Operators usually adopt a conventional solution at this stage, failing to view new technologies as a first alternative. Such technologies are usually considered only when they are vital for a specific field development.
Campos Basin, during the last 40 years, has been the stage where the technology development has played its main game in terms of pushing the offshore oil and gas production to overcome its challenges to go deeper and deeper in WDs never experienced before. Incremental, innovative, enabler or even disruptive technologies, supported by a strong commitment to success and the capability and drive for field test new ideas have made such a difference. Structured actions based on technology programs specific created for reaching defined targets, such as Petrobras Deep and Ultra Deep Water Technology Program named PROCAP, in its four sequential "versions" for over 28 years, resulted in two OTC Awards, in 92 and 2001, and helped Petrobras to achieve an important position worldwide in offshore production. A focused projection of the future in terms of the next generation under development to overcame challenges related to revitalization of Campos Basin mature fields, such as life extension methodologies, heavy oil processing, oil and gas contaminants treatment, subsea boosting and separation systems, power distribution and transmission, that are part of Petrobras technologies "gold list" are being developed and they will be available in the next couple of years. Additionally, an internal program, named Subsea Operational Technologies, has been developed to promote a full integration among suppliers, R&D and operation teams to reduce OPEX and enhance oil and gas production in Campos Basin. Also, associated to that, a strong and efficient integrated operation control has promoted the required offshore field management drive and safety. This paper will present a retrospective of the most significant Subsea system, Well Drilling and Completion, as well as Topsides technologies developed and deployed in the Campos Basin for more than 80 production systems in more than 30 oil and gas fields development.
Freire de Carvalho, Thiago Palmeira (Shell International Exploration & Production Inc.) | Olijnik, Luiz (Shell International Exploration & Production Inc.) | Broderick, Richard John (Shell International Exploration & Production Inc.) | Labes, Alan (FMC Technologies Inc)
The Parque das Conchas field in Campos basin offshore Brasil is a phased ultra-deepwater heavy oil development tied to the Espírito Santos floating, production, storage and offload (FPSO) vessel, moored at a water depth of 1,780-meters. The subsea system utilizes a subsea boosting and separation technology, enhanced recovery through water and gas injection, subsea sampling, enhanced vertical deepwater trees (EVDT), steel lazy wave catenary risers, and high voltage multiplexed electro-hydraulic steel tube umbilicals. During its nine year development since sanctioning, the professionals, installation contractors, commercial and contractual conditions have changed and played their role on the successful deployment of the subsea systems architecture. The project's successful track history to date is largely attributed to the development and consistent application of standardized subsea hardware throughout its three distinct and independently developed phases. This paper addresses the standardized features applied to the 10,000-psi (10K) rated subsea system components at BC-10: EVDT systems and tooling, including the upper completion tools which allowed deployment through either a subsea or surface blow-out preventer; completion and intervention riser systems on the lower riser package; retrievable flow modules and flow meters; production and injection jumper kits; manifolds; subsea boosting and separation; subsea control modules; umbilicals and subsea distribution hardware. This paper also addresses how these features fit within the operator's global subsea hardware standardization program, and provides examples on how continuous improvement, lessons learned and innovations are implemented in that program.
Abstract Many producing assets in the world have reached the so-called mature phase of development. Some of these assets have been producing for 30 to 40 years or more, which is typically beyond the design life, and have reached a water to oil ratio of 3 to 9 or more. There are many issues that affect the productivity and economic viability of these fields. Some of the challenges include integrity uncertainty in the wells, flow lines, and facilities; production bottlenecks due to the shift in gas, oil and water ratios; erosion/corrosion; increased sand production and handling costs; high chemical consumption and treatment costs; and obsolete monitoring and control systems that are incompatible with new technologies and which contribute to the need for a large number of operations staff. Generally operators are faced with the commercial decision whether to sell the asset to a low cost operator, reinvest in the asset, or incur the cost of decommissioning. While the number and complexity of these challenges are significant, there are nevertheless a number of viable options for extending the economic life of such assets. Hydrocarbon recovery and production from these fields can be enhanced by infill drilling; acid and fracture stimulation; by implementing a range of remediation techniques such as recompletion with smart systems to reduce water and solids influx to surface facilities; and by the implementation of improved and enhanced recovery methods. Selecting the optimal strategy requires a holistic perspective on subsurface issues, wells, and surface facilities, and an ability to make projections of integrated performance. This is greatly facilitated by first developing a root cause understanding of the reservoir and production fluid characteristics, and second, the use of analysis tools that allow quick and reasonably accurate assessment of options. In order to increase value from matured fields, the goal is to increase oil recovery from the historical average of 35% and to optimize production by improving the operational efficiency. To achieve this goal, in this paper we will put forward two key imperatives that extend the life of a mature field: (1) Finding and accessing the by-passed oil and (2) Maintaining High uptime during Asset production and operation. In this paper, several mature fields in Europe, Far East and Middle East are analyzed and presented in order to: –highlight the root causes for either low production and or higher operating costs; –assess the impact of both surface and subsurface uncertainties in multiple development planning scenarios; –develop the best strategies and options for improved reservoir, well and facilities management; –demonstrate the contributions of implemented new technologies that optimized performance of artificial lift, minimized downtime by well intervention and reduced operational costs by fluids flow assurance in well and surface facilities; and –list the technical and economical challenges that still face the industry.
Abstract Subsea processing and boosting can be key enablers or optimization alternatives for challenging field developments and their benefits increase with water depth, flowrates and step-out. Petrobras has invested a lot on the development of such technologies, supported, among other pillars, on an aggressive R&D policy through its technological programs like PROCAP, and several subsea processing and boosting systems have successfully operated in Petrobras fields. Considering that, these technologies are being considered for application in potential Petrobras' scenarios including mature and green fields. This paper aims to give an overview of the systems developed and applied in Petrobras prospects during the last twenty years, such as the Vertical Annular Separation and Pumping System (VASPS), Boosting Systems with Electrical Submersible Pumps (Mudline ESP and MOBO), Subsea Multiphase Pumps, Subsea Raw Water Injection and Subsea Oil-Water Separation (SSAO). It also reports the new R&D initiatives related to subsea processing and boosting that are being developed within PROCAP - Future Vision technology program, showing the main motivations of these developments, the main benefits of using each technology, the technological challenges and typical application scenarios. Also, this paper illustrates the analysis and evaluations performed so far, for all of the new developments presented. Introduction Petrobras has developed and applied several technologies during the last 20 years, forming a very useful " toolbox" for subsea processing and boosting applications. After successful implementation of several technology-projects, on subsea boosting and processing, Petrobras and other operators have demonstrated that such technologies are definitely a very important field development tool, as predicted decades ago. In the beginning of the exploitation of oil&gas offshore fields, the main concern is related to the initial investment to construct the production units, to drill the wells and to install all the equipment necessary for the production. During this phase, there is a lack of information regarding the field, mainly about the reservoir behavior. Normally, the reservoir behavior is calibrated during the productive life of the field. Due to this, the operators usually adopt a conventional solution, not considering the use of new technologies as the first alternative. These are considered most when they are vital for a specific field development. For most fields in Campos Basin, Brazil, the main recovery mechanism for reservoirs, since the beginning of the production, is waterflooding. A typical curve of produced fluids starts with the predominance of oil, rising to the production plateau, until the water breakthrough occurs. At this point, the production presents increasing water content in the liquid stream. So, as it is necessary a massive water injection to keep the pressure of the reservoir, after a few years the watercut of the production increases a lot. Additionally to the two aspects described above, there is also a need to overcome the constraints of existing platforms. These motivations led Petrobras to start in the early 90's the development of subsea processing and boosting solutions. Technological Programs were created to support these developments. Several processing and boosting projects were installed since year 2001, when the VASPS was deployed in the Marimba Field (Campos Basin, Brazil). These projects will be described in a brief way in this paper, focusing their main technological aspects.
Duarte, Daniel Greco (Petrobras) | De Melo, Alysson Vinicius (Petrobras) | Cardoso, Carlos A.B.R. (Petroleos Brasileiro S.A.) | Vianna, Flávio (Petrobras) | Irmann-Jacobsen, Tine (FMC Technologies) | McClimans, Ole Thomas (FMC Technologies) | Barta, Pavel (FMC Technologies) | Elamin, Zabia (FMC Technologies) | Moe, Randi (FMC Technologies) | Machado, Paulo (FMC Technologies)
Abstract This paper presents hydrate design premises established to reach the finaldesign and operational philosophy for the 3 phase subsea separation system, also known as Marlim SSAO. The main purpose of this pilot station is toseparate the produced water and reinject it into reservoir for pressure supportwhile routing the oil and gas to topside. Since the subsea process station handles multiphase flow where gas and freewater are present, and the system is exposed to low temperatures by the ambientcold sea water, a good strategy to avoid hydrate formation is necessary. Thehydrate strategy must be incorporated as a part of the total system design andshall handle all critical operational scenarios as shut-down and start-ups. Thehydrate strategy is closely linked to the temperature control and theevaluation of need for thermal insulation of the system. Temperature control isalso important in the system because of high sensitivity in fluid properties. General thermal insulation verification analysis and detailed studies of coldspots are required. Real fluid testing was included in order to better evaluatethe hydrate potential. The Marlim SSAO, as an integrated part of a field system from subsea wells totopside, is divided into several parts for the facilitation of the flowassurance and the hydrate prevention strategy: Multiphase lines, water linesand water injection system. The hydrate prevention is very challenging becauseof several open connections between the multiphase lines and the water lines. Hence, usual means as MEG inhibition and thermal insulation have not beenenough to ensure the hydrate prevention strategy and new strategies have beendeveloped. It has been necessary to challenge the strategies in every part ofthe system. The results of the work methodology and the analysis executed indicated thatMarlim SSAO is a safe system to operate from a flow assurance and hydrateprevention point of view. The material presented in here intends to establish akey reference for preservation design of 3 phase subsea separation systems. Itapplies for future generations of these kinds of equipments. Introduction The Marlim SSAO is a subsea processing pilot station which has been installedin the Campos Basin off the coast of Brazil. The objective is to separate mostof the water from the production stream and re-inject it into the reservoir forpressure support while transporting the oil and gas to topside. The SSAO isinstalled at a water depth of 876 m, 341 m from the production wellhead and2100 m from the injection wellhead. The hydrocarbons will be sent to thetopside facilities 2400 m (riser and flowline length) from the SSAO. This paper describes the challenges and innovative solutions on flow assuranceand hydrate prevention strategy for the Marlim SSAO. This includes the mainphilosophy, the preservation of the station in different operational modes, evaluations of identified risks, and calculations and analysis performed tosupport the strategy.
This paper describes the latest R&D initiative from Petrobras, the PROCAP FUTURE VISION program. The objective of the program is to develop disruptive and innovative technologies to radically change the way we develop and produce oilfields offshore.
The PROCAP FUTURE VISION program has a portfolio of 19 projects, encompassing all the disciplines in the E&P area, but approaching each one of them in an innovative way by combining the use of disruptive technologies and exploring the positive synergies among them in this process.
A configurable FPSO - the "FUTURE FPSO"- with "plug and play" compact process equipment associated with subsea processing and power distribution is an example of such synergetic combinations.
There is an extensive degree of use of nanotechnologies in several projects, from developing nanostructured materials, nanosensors to assure system integrity, nanoparticles to improve recovery or to helps gather information from the reservoirs.
The use of augmented reality and robotics is being analyzed in the program as a way to reduce the number of crew members offshore, therefore enhancing safety and reducing logistic costs.
Laser drilling is a very promising area that together with riserless drilling and the use of sensors to monitor the well integrity and optimize production will significantly improve economics.
A study is being carried out to evaluate the economic impact of the combined use of all those technologies in a Pre-Salt field offshore Brazil. The qualitative results of this study will be presented.
As part of the overall strategy of the Company, Petrobras is assuring that not only the technology is developed in a timely manner but also with the early involvement of suppliers and service provides installed in Brazil to allow the fulfillment of local content requirements while developing technology locally in a competitive basis.
The paper will describe in detail the PROCAP FUTURE VISION program, the Strategy to execute the program and an evaluation of the benefits Petrobras expect to harvest from the application of those breaktrough technologies in an offshore development.
There are strong arguments for moving water processing from deepwater platforms to the seafloor in many fields. There need to be, given the daunting challenges to doing so.
One of the prime targets is older offshore fields producing more water than oil. When the water treatment facility on the topside reaches its capacity, it puts a cap on oil output. The rising water cut increases the force needed to lift a production stream holding ever less oil, as the pressure in the reservoir declines.
Ultimately the natural force isn’t enough to lift the water and oil from deepwater fields, which will mean the end of production if nothing is done. “When you can’t get it to the surface, you are left with nothing, unless you have got a way to pump it,” said Tim Daigle, senior project engineer at Fluor Offshore Solutions. There are two ways to do that: Increase the lift with pumps, or reduce the load by removing the water on the seafloor and disposing of it there.
After nearly two decades of development and testing, the latter option is beginning to emerge as an alternative. Oil companies are turning to subsea processing for projects that are challenged by the economics, looking for ways to make them profitable, or to improve their results, said Mike Robinson, a sales and marketing manager at FMC Technologies, which is a leader in this area.
Statoil’s Tordis field offshore Norway shows the upside and downside of subsea water separation. The company predicted the combination of subsea water processing and improvements in the pumping system on its Gullfaks C platform would increase ultimate production by 35 million BOE, pushing the field’s recovery rate from 49% to 55%. The design is based on what Statoil learned from its earlier pilot test installed on its Troll C platform in 2001, which is still processing 50,000 bbl a day and reinjecting the water into an aquifer.Rune Ramberg, chief engineer of sub-sea technology at Statoil, said there are many reasons for the Norwegian company’s push to develop subsea water treatment systems. It has long relied on subsea completions. Developing Arctic resources will require alternatives to offshore platforms, which are vulnerable to ice. And most importantly: “We are not making money transporting water,” Ramberg said.
Deuel, Charles Lloyd (Shell International Exploration and Production Inc. ) | Chin, Y. Doreen (Shell International Exploration and Production Inc. ) | Harris, Jonathan (Shell UK Ltd.) | Germanese, Vincent James (Shell Brasil Ltda.) | Seunsom, Noy (Shell Oil Co.)
Abstract Parque das Conchas (BC-10) is a deepwater development offshore Brazil. A novel Caisson / Electrical Submersible Pump (ESP) subsea separator (gas/liquid) and pumping system to enhance production and maximize recovery has been utilized as part of the development of two of the fields (Ostra and Abalone). A third field, Argonauta B-West utilizes multiphase boosting with a modified Caisson/ESP (C-ESP) system to operate with a single, non-separated multiphase outlet. These novel designs have significantly impacted system and flow assurance engineering such as separator level control, hydrate mitigation, system operability, and chemical injection. The fields have been successfully started up with production through the subsea processing system since late 2009. This paper outlines the performance of the subsea processing and production system from the perspective of flow assurance, and presents comparisons of the actual operating performance to design expectations. Learnings from key factors that strongly impact the production system operability and operational strategies are discussed, including the achieved separation efficiency of the caisson, the impact of defoamer performance on caisson operation and the importance of the hot oil circulation system. Introduction Parque das Conchas (BC-10) is a deepwater (~ 6000 ft) development located at Campos Basin, approximately 75miles southeast off the coast of the city of Vitoria in Brazil. Shell is the operator with a 50% interest, in a joint venture with Petrobras (35%) and ONGC (15%). Since its startup in July 2009, BC-10 has been in successful production. The properties of the fluids in the BC-10 reservoirs vary considerably with depth from heavy, low GOR fluids to light, high GOR fluids. These properties, and the fact that BC-10 requires subsea artificial lift to achieve economic production rates posed severe challenges for the design and operation of the subsea system . Figure 1 provides an overview of the development. The Ostra and Abalone fields are produced in a commingled mode. The Ostra field has 6 producers and 2 production manifolds (PM1 and PM2). An artificial lift manifold (ALM1) equipped with four separated C-ESP systems connects to PM1 via flowline jumpers. The produced fluids from the wells flow into three caissons while the fourth caisson stands by as a spare. The well streams entering the caissons (currently at over 1200 psig) are separated into gas and liquid phases. While the separated gas flows into the Ostra gas line, the liquid flows down the length of the caisson and is boosted by the ESP and enters the Ostra oil line. The B-West field has a stand-alone subsea production system. The two producers are connected to two non-separated C-ESP systems located at artificial lift manifold 2 (ALM2). Each producer is designed to flow to its own caisson and flow to topsides via its own subsea flowline. In addition, the producers can be directed into one caisson and flow via one flowline to the FPSO while the other flowline works as the service flowline if needed. Both Ostra and B-West require subsea artificial lift to achieve economic rates, due to their low reservoir energy. The novel subsea hardware and design provides robustness and flexibility to ensure sustainable production performance, and to safeguard the subsea production system after shut down.
Abstract The recovery of crude oil and gas from deepwater fields present significant challenges for flow assurance and production chemicals. In deepwater environments, production is often complicated by multiphase fluid flow, diverse fluid compositions and high fluid viscosities. In this paper, we describe the use of chemical knowledge, field experience and laboratory testing to develop a chemical antifoam to mitigate crude oil foaming for the unique Parque das Conchas subsea project, located in block BC-10, offshore Brazil. The Parque das Conchas project employs subsea separators and electric submersible pumps contained within subsurface caissons. Without effective management, the potential exists for crude oil foaming to negatively impact the efficiency of subsea separation equipment and the operability of the entire production system. The challenging subsea production conditions necessitated a high performance umbilical qualified defoamer to mitigate this flow assurance issue. Laboratory testing of Parque das Conchas crude oil under simulated separator and flow line conditions was conducted to evaluate antifoam products. Based on test results, a fluorosilicone antifoam product was selected. Preliminary field performance has proved to be excellent with behavior of the produced fluids and antifoam correlating with expectation and laboratory simulation, confirming the approach taken. The crude oil antifoam product developed for Parque das Conchas is the first in the industry that is qualified for a deepwater project utilizing both subsea separation and boosting. Introduction The term flow assurance refers to " the ability to economically and without interruption produce petroleum from the reservoir to the production facility?? (B. Fu, 2000). Flow assurance problems can occur, however, even with uninterrupted fluid flow as demonstrated by emulsification and foaming (L.L. Laurence, 1981). The ability to predict, monitor and prevent such problems is necessary to optimize petroleum production under all process conditions (M.K. Poindexter et al., 2001). This paper will focus on the development and deployment of a production chemical antifoam for the challenging conditions at Parque das Conchas, which represents an " industry first time?? antifoam application for subsea separation caissons. Field Description and Flow Assurance Challenges Parque das Conchas is a deepwater (~ 6,000 ft) development located in the Campos Basin, approximately 120 km southeast from the city of Vitoria off the coast of Brazil. Phase 1 of the development involves production from three fields: Ostra, Abalone and Arganauta B-West. Phase 2 is currently under development with planned first oil in 2013. This comprises the development of the Argonauta O-North field. Shell is the operator with a 50% working interest, in a joint venture with Petrobras (35%) and ONGC (15%). The Parque das Conchas development differentiates itself from other conventional subsea designs by its unique flow assurance characteristics including:Subsea separation and boosting systems located at Ostra field Subsea multi-phase pumping systems located at B-West field