Late in the evening of a wintery night, a worker is hurrying to respond to an alarm that has gone off. The worker is severely injured. The ensuing investigation finds that the incident could have been prevented if the equipment had been engineered properly. How many times have you heard of incidents that have severely injured a person and you thought, "That incident could have been prevented if only the equipment had been engineered properly?" However, equipment is often installed without taking into consideration how it can be engineered properly to minimize or eliminate operating risks. The safety of an onshore facility is a function of how safely the facility is designed. People are hurt and sometimes killed when explosions, fires, and toxic-gas releases occur at oil-and gas-producing facilities that were designed without regard to measures that could have prevented such incidents. The safety of people and equipment needs to be considered and included along every step in the engineering of oil and gas facilities. Properly designed oil and gas facilities can eliminate injuries and deaths. Many wellsites, tank batteries, and production facilities are at risk because of design or installation errors. These errors may have occurred when the facility was built or occurred over time because the facility had been continually "added on to" through the years. Lack of proper engineering design can lead to equipment failure, lost production, human injury, or harm to the environment. This paper reviews the key areas for facility designers and engineers to include when designing facilities to ensure safe facilities. Use and incorporation of all safety engineering principles outlined in this paper should enable facility engineers and designers to build safe facilities that reduce the risk of major incidents. One of the first questions asked by corporate executives and investors after a new discovery is, "How in the world are we going to produce this?" The completion engineers quickly figure out how to get the highly valuable well fluids to the surface. Then, everyone turns to the production and surface-equipment experts and asks, "What equipment are we going to need to treat and sell oil and gas from this new discovery?" The answer to this question will impact the safety and health of perhaps generations of workers who will be working on and near this equipment for decades while the oil and gas is being produced. At this point, companies have the option of following two different paths. The first path is the "high road" of making sure that all facilities are designed and operated in accordance with good
The burning of oil in place (in situ) on water is a viable means of mitigating the impact of marine oil spills. This paper defines three phases of decision-making, prioritizes the key issues of each phase, and proposes a process for analyzing the issues when considering controlled in-situ burning as an early response option in both icy and warm conditions. Also provided is a fact-based consideration of safe practices, such as those involving potential personnel exposure, sealife exposure, ignition control, fire control, and vessel safety. Controlled in-situ burning (ISB) can be initiated on a pre-approved or case-by-case basis, and there is generally a short operational time window during which it can be effectively used; therefore, quick, informed decision-making is imperative. This paper provides a discussion of these factors, along with a knowledge base of best practices that includes general categories of considerations, decision-making support tools, and specific operational approaches. The Deepwater Horizon response is used to illustrate both the operational approaches and the three decisionmaking phases; however, every situation is different and calls for decisions based on the individual circumstances. Because of its long history of research, testing, and use during spills, as well as positive environmental tradeoffs, controlled ISB is now considered by many to be a conventional response option. On a number of occasions over the last 50 years, controlled in-situ burning has been used to remove oil spilled on water (Fingas 1999). Today, because of decades of research and testing, controlled ISB has an immense knowledge base and an impressive success rate. According to the US Coast Guard (USCG), the National Oceanic and Atmospheric Administration (NOAA), and the US Environmental Protection Agency (EPA), controlled burning removed between 220,000 and 310,000 bbl of oil from the Gulf of Mexico during the response to the Deepwater Horizon (DWH) spill in 2010 (Schaum et al. 2010; Aurell and Gullett 2010; Lubchenco et al. 2010; Allen et al. 2011). However, experts in controlled ISB have noted that the paradoxical nature of igniting a fire as a response tactic and the emissions produced by the burning oil have been hurdles for the response community to overcome in terms of public perception. In reality, fire can easily be controlled, and using it to remove spilled oil from the offshore environment has more pros than cons.
Tomorrow's energy needs are driving the industry to pursue the concept of "no oil left behind." But this goal comes at a cost as the pressures in remote deepwater reservoir pockets are depleted and the water cuts increase. Existing technology is evolving to meet the challenges to automate water separation and purification in deepwater for environmentally safe discharge at the seabed. To solve these problems, the objectives must be defined; the best available solutions must be selected, and the technology gaps must be identified and closed. Environmental protection is a priority, and the translation of the existing statutory regulations regarding discharged water quality is the starting point. Safety and reliability will follow along with the flexibility to tailor the system to match the reservoir's changing needs and to incorporate the best, newest, and fastest-developing technology. Equipment relocation may also prove commercially attractive. Major challenges will include remote process train control and monitoring, and the ability to perform routine maintenance while the wells still flow. Some of this technology could have immediate benefits to surface processes that would in turn provide ideal proving grounds before the technology ventures into deepwater. This paper explains the challenges facing subsea processing technologies in handling and treating produced water at the seabed between 5,000 and 8,000 feet of water depth. It will discuss the regulatory standards used throughout the industry today to oversee produced water treatment (PWT). The paper will look at the marine life in this ultradeepwater (UDW) environment at the seabed conditions. It will also review the latest PWT technologies used throughout the topside offshore production industry. The paper will illustrate various concepts to perform subsea PWT and look at the many challenges and gaps to be addressed to make this technology viable and effective. The paper will also identify the gaps and challenges to applying PWT and discharge at the seabed in UDW environments. Research and compiled information will be presented to support the concepts proposed to meet the challenges of PWT and discharge at the seabed in an UDW production system.
This paper analyzes the various selection methods of integrated template structures (ITSs) for use in the Arctic environment. First, an analysis of several actual projects is carried out, with the specific features of each described thoroughly. An important part of the work is devoted to the requirements of ITSs conceived in relevant NORSOK (Norsk Sokkels Konkuranseposisjon), International Organization for Standardization (ISO), and DNV (Det Norske Veritas) standards. The main elements of subsea production modules are examined in this work, along with their specific characteristics and components. Operation and installation of subsea modules in the Barents Sea are also analyzed in this paper. Four scenarios, with differing numbers of ITSs (two, three, four, and six) and differing quantities of well slots in each, are considered. For each scenario, a study of related marine operations (required for installation) is performed, and a program for installation-cost estimates is developed, resulting in the determination of an optimal design for the ITSs. Various parameters affecting the cost of subsea infrastructure are analyzed and studied from different perspectives (e.g., geometrical well-pattern systems, distance between drilling slots, drilling and construction costs). Risk analyses of the threats and consequences involved in the process are performed, and risk-assessment matrices and mitigation actions are established. As a result, a model for selecting an optimal ITS for the Arctic/Sub-Arctic region is created. Some of the already-executed offshore projects (from Terra Nova and White Rose on the Grand Banks of Newfoundland in eastern Canada to Snøhvit in northern Norway) are followed by those still being prepared, such as Goliat and Skrugard in northern Norway. All these projects may be considered as true milestones toward oil and gas development in the Arctic region. Therefore, a review of these projects was performed while writing this paper to provide an important basis in experience. Because of this accumulated experience, we can turn future concepts into today's reality. This paper states important facts regarding ITSs and describes specific requirements for the Arctic environment. When dealing with operations in Arctic regions, a careful selection of installation vessels is very important; therefore, we present a short comparison of these vessels in a later subsection. Finally, because risk analysis must be performed before the start of any operation, a section regarding risk assesment is also included. This paper presents the analysis of ITS selection in three parts-- installation costs, construction costs, and total expenditures.
The Huizhou oil field is located at the Pearl River mouth in the continental-shelf region of the South China Sea, with an average water depth of approximately 117 m. The oil field's main facilities include eight fixed-jacket platforms, two subsea-production wellheads (HZ32-5 and HZ26-1N), and one floating production, storage, and offloading (FPSO) vessel (Nanhai Faxian). Figure 1 illustrates the general layout of the field. The peak daily oil production is approximately 70,000 BOPD. In September 2009, after a strong typhoon (Koppu) passed over this oil field, the FPSO vessel's permanent mooring system was seriously damaged. All production risers connected to the FPSO vessel's turret were ruptured, and production was forced to shut down.
The floating production, storage, and offloading (FPSO) facility Espirito Santo, located offshore Brazil in the Parque das Conchas (BC-10) field, is the world's first turret-moored FPSO facility to use steel risers for fluid transfer. The FPSO facility is moored in a water depth of 1780 m, and the internal turret incorporates a total of 21 riser and umbilical slots. The steel risers, which are in a lazywave configuration, were pulled into the turret through inclined I-tubes. Clamps at the top of the I-tubes retain the risers, thus transferring axial loads from the risers to the turret. A clamp casting welded at the bottom of the I-tubes houses a stopper arrangement designed to transfer shear forces and moments from the risers to the turret. The FPSO facility began oil production in July 2009, and now has more than 5 years of operational experience. During this period, inspection of the riser system and the associated flex joint has confirmed the integrity of the design, giving further confidence in the use of steel risers in turret-moored systems. The in-service inspection of the riser system is described, and the results are reported. The Parque de Conchas (BC-10) field is located offshore Brazil in the northern Campos basin, approximately 120 km southeast of the city of Vitória (Figure 1). The project is a joint venture, with operator Shell holding a 50% interest and partners ONGC and Qatar Petroleum International holding 27% and 23%, respectively. The development of BC-10 is based around a centrally located floating production, storage, and offloading (FPSO) facility; subsea wells producing through manifolds; subsea pressure-boosting systems; and a network of flowlines and risers. The development plan comprises three phases, of which the first two are complete. Phase 1 involved the development of three fields tied back to the FPSO facility by means of subsea wells and manifolds. These fields were the Ostra, Abalone, and Argonauta-BW, and their development involved nine production wells and one gas-injection well. These fields came on stream in July 2009, with a peak production of 94,000 BOE/D. The field layout is shown in Figure 1. Phase 2 of the project, the tie-in of the Argonauta-ON field, came on stream in October 2013, with an expected peak production of 35,000 BOE/D. The joint-venture partners have also agreed to a third phase, which will include the installation of subsea infrastructure at the Massa and Argonauta O-South fields. Once on stream, Phase 3 is expected to have a peak production of 28,000 BOE/D.
Sand and solids are removed from production separators either off line (shut down for physical removal) or on line by use of jetting systems. Traditional jetting designs use spray nozzles to fluidize and push the sand toward a covered outlet to evacuate the solids from the vessel. Cyclonic-jetting technology combines the fluidization and evacuation functions into a single, compact device. On the basis of a hydrocyclonic platform, this technology converts jetting spray water into shielded vortex flow that fluidizes sand in a circular zone without disturbing the oil/water interface. Total solids removal is primarily a function of set height, spray flow, and spacing. A single unit was optimized at a set height of 10 cm (4 in.) with spray pressure of 0.7 barg (11 psig) to provide an area of influence of 1.1 m² (12.0 ft²) with 28 cm (11 in.) of sandbed depth. Placing two units in parallel with overlap of their affected zones reduces the "egg-carton" effect associated with this technology; ...
In the international regulation framework, the energy-efficient operation of ships is becoming standard. In this respect, restrictions on new construction appear to encourage improvement to existing vessels often equipped with outdated technologies. One of the relevant aspects of propulsion plant design and fleet management is the propulsion need to accomplish the design requirements in a wide set of sea states or in conflicting operative conditions (e.g., laden/ballast, sailing/trawling), requiring very different performances. A preliminary assessment of the energy efficiency of the ship system is then crucial for optimizing both the operating costs and the impact on the sea environment. A new efficiency assessment method that includes engine fuel consumption evaluated by ad hoc statistic regressions and ship resistance in calm water and in waves computed by a 3-D boundary element method is proposed. An application to a hard-chine 18 m trawler is proposed as part of a wider decision support system or weather routing algorithm.
Ships are a significant source of air pollutants, such as sulfur oxides (SOx), carbon oxides (COx), and nitrogen oxides (NOx), that have a relevant impact on both some sea ecosystems and populated coastal areas, especially those close to harbors. Although the International Maritime Organization (IMO) introduced the greenhouse gas (GHG) emissions reduction in its agenda in 1995, only in recent years has this seemed to generate constraints on the design of new units (see, for instance, Coraddu et al., 2014). In addition, considering that most pollutants are strongly related to a vessel’s total fuel consumption, optimizing the propulsive efficiency directly reflects as a reduction of exhaust gas emissions. From a designer’s point of view, the need to improve the available methods for efficiency prediction and optimization to achieve better solutions at very preliminary design phases is clear. For example the IMO (2009a, 2009b) introduces technical and economical indexes for emissions regulation, namely, the Energy Efficiency Design Index (EEDI) and the Energy Efficiency Operational Indicator (EEOI). The former is used to assess the design of a vessel, the latter to evaluate the operational profile of a vessel. Despite the relevance of these indexes, some types of ships, such as cruise ships and working boats, are not included in the baseline values provided in the International Convention for the Prevention of Pollution from Ships (IMO, 2011). Moreover, the proposed baseline values do not take into account the environmental conditions in which ships navigate.
Gas scrubbers are designed to protect process equipment, such as compressors, dehydration towers, pipelines and molecular sieves from liquids. The efficiency of gas scrubbers for separating natural gas liquids (NGLs) is critical to the recovery of most of the entrained NGL before the gas is routed downstream to pipelines.
We present a specific case study in Southeast Asia where offshore production was delivering 300 MMscf/d of gas to an onshore gas processing facility. The gas was chilled in a mechanical refrigeration unit, and liquids were separated in a vertical scrubber equipped with a simple inlet device and mesh pad assembly. The scrubber was designed to handle 450 MMSCFD. Due to an inefficient scrubber design, the facility was experiencing NGL liquid carryover from the scrubber into the pipelines with the original design basis. The scrubber thereby showed significant amount of liquid carryover of 1,550 BPD of natural gas liquids into the gas pipelines.
Computational fluid dynamics modeling of the scenario clearly showed loss in separation efficiency and NGL carryover from the scrubber to the downstream pipeline, documenting that the existing scrubber was not suitable for such high gas loading and increased gas volume.
Customer approached Schlumberger to retrofit scrubber with a new design and resolve the existing liquid carryover issues which led to revenue loss. We have experience in desiging novel internals such as axial cyclonic inlet (ACI) in these kind of scrubber vessels. These have been tested and optimized in the laboratory using model fluids and further tested in a high-pressure real fluid testing loop. Test results show that ACI provides the required gas/liquid separation efficiency under the higher gas loading and thereby increases the overall separation efficiency to 99.9+%.
The retrofit scrubber was designed to process 450 -500 Mmscfd of gas and increase the NGL production by 8540 BPD showing high ROI for the customer. The scrubber with the ACI shows consistently higher separation efficiency even under turndown or lower inlet gas flow conditions.
We present details of the retrofit scrubber design, importance of using high efficiency separation internals, CFD anlaysis and present test results verifying the liquid carryover before and after implementation of the new inlet section.
ADGAS is a leading LNG producer. It is the pioneer LNG supplier in the region. LNG trains are operated since 1977. Through those years of experience, ADGAS has been following a stringent Asset Integrity Management System for all its plants. Among these plants are the flare and relief systems. Flare systems are considered safety critical. Maintaining the integrity of these systems is a challenge. This paper shares ADGAS best practices in maintaining the asset integrity of these plants. The paper also highlights the latest development in the area of flare systems inspection and shares same case histories.
The world of Asset Integrity Management has advanced over the few decades to a great deal. Inspection has progressed from being time based to condition based then to being Risk Based. ADGAS Asset Integrity Management has passed through all these developments. For instance inspection of flare systems and plants was first time based. Then based on the performance of some of its plant systems it became condition based. Afterwards more optimization was added and it became Risk based. Technology has also advanced across the years, for instance, flare tips replacement was a strictly time based program. Then became condition based, then now we can inspect the flare tips systems online using special Unmanned Aerial vehicles (UAV's). This enabled ADGAS to truly optimize on maintenance and replacements of the flare tips. These examples will be shared in the paper. Furthermore at few instances failure of some flare systems provided great experience to avoid recurrence, flashback case, flare piping systems ageing and repair are all cases that are to be shared in the presentation.
Utilization of latest inspection technology, latest repair technology and monitoring enabled ADGAS to optimise its inspection and maintenance costs. The last savings on flare systems maintenance were estimated at a value of USD MM 3.5. Some old flow control measures were proven to possible create problems, for example restriction orifices to control the flow of purge gas can get blocked if not maintained. Restriction orifices can be changed for other means of control to avoid possible restriction of purge gas flow which is essential for the integrity of flare systems.
Latest UAV inspection technology has added towards the inspection and maintenance of flare systems. Utilization of more advanced monitoring and flow control of flare purge gases is of high importance. Usage of novel techniques in piping repair represented an important aspect in optimizing the maintenance cost of flare systems.