The paper will present the main drives that PETROBRAS has to overcome the challenge of producing in water depth up to 3000m. It presents also the PROCAP-3000, the in-house Technological Program on Ultra-Deepwater Exploitation System, and its main projects developed to be able to achieve the goals. The paper presents in addition the major challenges in the following areas: flow lines, risers, completion riser, boosting, and subsea equipment. The main projects of each area will be discussed, the main results presented and the challenges pointed. Petrobras technical staff believes that the above technical areas and the chosen projects, to be presented, play a key-hole in ultra-deepwater production, not only in Brazil, but also all over the word in deepwater developments.
Petrobras has a total of 14,89 billion boe proven reserves in December 2004, according to SPE methodology. This number corresponds to Brazilian reserves (13,02) and international (1,87). The production in Brazil has reached a record of 1,820 mil bopd this last May with a increasing tendency.
In 2004 Petrobras had a annual averaged production of 1,758 mil boepd. Onshore contributes to 21%, 18% in shallow water up to 300 m. Deep water from 300 to 1500m contributes with 55% , the large majority, and 6% from WD deeper than 1500m, as can be seen on figure 1.
From figure 1 also, it can be seen that the onshore reserves represent only 10% of total reserves. Offshore bellow 300 m, 11%. From 300 to 1500 m, lies the majority, 56% of the total reserves. It calls the attention that 23% of total reserves are bellow 1500 m of WD.
It can be seen also the exploration area, from the total 36% are at WD bellow 1500 m, in other words: the future lies in ultra-deepwater.
From those numbers one can say that Petrobras will consolidate its production in deep and ultra-deepwater.
The Company plans to reach a 2,3 million bopd production in 2010, in Brazil, close to 75% from deep and ultra-deepwaters. This goal, that will allow Petrobras to produce from several already found fields, constitutes the main objective of PROCAP-3000, the Petrobras in-house Technological Program on Ultra-Deepwater Exploitation Systems. More specifically, it seeks to find solutions that will make oil found at depths of up to 3,000 meters technically and economically viable.
The PROCAP 3000
To be able to tackle all technological challenges Petrobras, in 1886, organized its personnel in a program called PROCAP, and defined very clear objectives according to the water depth. Basically three programs were created with the following objectives:
In every country the stake holders in the local down-stream oil industry engage in negotiations and interact in an ongoing process that results in a local industry dynamic. The overall objective of an efficient and appropriate industry is universal but the resulting outcomes vary significantly. The local forces that have resulted in these differences are examined.
The local State strives to broker a process to balance down-stream industry income with local consumer interests. This dynamic is of particular importance in developing markets where inward investment is often wanted but domination by foreign multinationals is not welcome. There is little correlation between local levels of affordability and fuel trade margins gained by the trading companies. Driving forces noted include; land control, local and foreign company influence, oil company vs dealer leverage, operational standards with linked controls. Guide lines on fuel trade margins with linked resultant industry facilities are reported.
Multi-national companies, locked into their own publicized non-negotiable international standards, will drive up local standards to level the playing field, while local operators will typically adopt "local pragmatic standards". The multi-nationals will leverage their strong brands in price control markets or on locations of high volume trade. The growing regional oil companies have their strength of lower overheads and linked capacity to operate smaller sites. The State strives to balance these forces, supporting local small business and employment. Foreign policies are easy to copy and legislate but typically difficult to manage. The case study of the differing outcomes of Kenyan and Uganda deregulation of the retail fuel price are examined.
Upgraded fuel specifications, tougher environmental standards, closer fuel retail linkage to shops, increased automation and broader access to international best practice will continue to require the adjustment of the respective local down-steam markets. We have the shared responsibility to increase our shared knowledge of this dynamic and build a more efficient industry.
Managing Constructive Down-Stream Competition.
This paper considers the down-stream market of Africa in the broader context of Europe and the Middle East. It considers the driving forces of competition, state and economic environment interaction that result in a local market. Differing processes and forces have fashioned these markets with resultant differing outcomes. This paper strives to examine some of these to better understand this dynamic.
In words taken from the World Petroleum Council, we are here to “encourage the application of scientific and technological advances and the study of economic, financial, management, environmental and social issues relating to the petroleum industry” It is hoped this paper contributes to this advancement and triggers further debate of value to participants and their domestic industries.
Forces that shape a local down-stream market.
In each local down-stream market the quality of offer and service enjoyed by the local consumers is driven by the fuel marketing margin and the volume concentration of the trade. Volume concentration must be included because if local land controls result in a few large trade volume sites, these sites are able to offer better services.
Xie, Zaiku (SINOPEC Shanghai Research Institute of Petrochemical Technology) | Liu, Zhongneng (SINOPEC Shanghai Research Institute of Petrochemical Technology) | Yang, Weimin (SINOPEC Shanghai Research Institute of Petrochemical Technology) | Zong, Hongyuan (SINOPEC Shanghai Research Institute of Petrochemical Technology) | Wang, Rongwei (SINOPEC Shanghai Research Institute of Petrochemical Technology)
Only about 5 % of the global annual gas consumption is used for the conversion to ammonia, methanol and some other chemicals. The proven natural gas reserves to production ratio, i.e. lifetime is about 100 years for Africa and 260 years for the Middle East. Taking into account the total amount of gas being flared world-wide which is corresponding to the feedstock of 74 Mega-Methanol plants of 5000 t/d each, there is a real challenge regarding large-scale monetisation of these gas sources in accordance with environmental aspects.
The technology development in the conversion of gas has to consider easily transportable valuable products. Also it must cover the logistics for bringing these products to the market.
What first comes to mind with GTL is Fischer-Tropsch, the classic route from coal or natural gas to transportation fuels (synfuels). Lurgi on the other hand promotes methanol-based technologies for upgrading of natural gas to value-added products.
Since Lurgi introduced its new groundbreaking MegaMethanol® process for plants with a production of 5,000 tons of methanol per day and more, methanol will be available at a constant low price in the foreseeable future. The first such plant started up in fall 2004 and operates smoothly at 100%+ capacity since early October. This development has an enormous impact on down-stream technologies for the conversion of methanol to more valuable products.
The first derivative of methanol in this context is DME which has a high potential as alternative to conventional diesel fuel and as feedgas for gas turbines in power generation. The next step is the use of methanol as feedstock for the production of olefins which is one of the most promising new applications. Lurgi's new Methanol-to-Propylene (MTP®) process presents a simple, cost-effective and highly selective technology.
Lurgi reported about these developments at the 17th WPC in Rio de Janeiro. Now, two years later we can present the first steps into commercialisation - especially of the gas to propylene route.
Natural Gas in the 21st Century: A Key Feedstock for (Petro-) Chemicals
The total proven gas reserves amount to approx. 180 trillion cubic meters world-wide which translates into a gas reserve-to-production ratio, i.e. a gas reserve lifetime of 70 years. Furthermore, estimated additional gas reserves will cover a lifetime of 65 years more.1 Compared with the reserve lifetime of 41 years for petroleum and 230 years for coal, there is no doubt that natural gas will be a key fuel component in the 21st century. However, a considerable portion of this reserve is wasted yearly: more than 80 billion cubic metres of natural gas and oil associated gas are flared for technical reasons or for lack of markets. This explains the main incentive for engineers and environmentalists as well to come up with novel ideas for the utilisation of this gas.
Existing technologies for natural gas conversion are based on the conversion to synthesis gas (or short: “syngas”, a mixture of carbon monoxide, CO, and hydrogen, H2) and from there to hydrogen and ammonia, Fischer-Tropsch products as well as methanol and DME.
Girassol and Jasmim are two deep-offshore oil fields in Angola Block 17, operated by TOTAL E&P Angola.
The development of the fields calls for drilling a total of 40 wells. Girassol has been on production since December 2001, while Jasmim started in November 2003.
Among all the solutions implemented to help minimise well interventions, always extremely costly in deep-offshore environment, the most valuable for reservoir engineering have been the downhole permanent gauge (DHPG) and the downhole flow-control devices (smart completion).
DHPG have been installed on all producers, and on selected water injectors. They have proven invaluable for the understanding of intra-reservoir and inter-channel systems communications, assisting in optimisation of well locations and reservoir management decisions. DHPG have been used for:
- daily pressure and temperature monitoring
- interference tests - mostly performed in the early life of the reservoirs to assess communication through faults and reservoir characteristics between wells
- pressure transient analysis - data have been routinely recorded during operational shutdowns to minimise wells production downtime
- remote pressure surveys - before a well is connected, an acoustic module and transducer is lowered on the wellhead and electrical data from DHPG are converted into acoustic signal that can be read by a sensor located on sea surface. This allows to monitor the static pressure and measure the interference with other wells.
On Jasmim field, a few wells have been equipped with a smart completion. The equipment allows independent and progressive downhole control of the flow from separate reservoir units, according to their potential and evolution. One year after the first installation, the smart completions have met the demanding expectations of both Completion and Reservoir Engineers.
This paper presents some of the techniques used on Girassol and Jasmin fields for monitoring and flow control that proved to be very useful for the optimisation of the development.
The Girassol and Jasmim fields are located offshore Angola on Block 17 about 150 Km off the Angolan coast.
The block 17 is operated by Total E&P Angola under a Production Sharing Agreement (PSA), between the concessionaire Sonangol and the contractor group including Total (40%), Esso (20%), BP (16.66 %, Statoil (13.33%) and Nork Hydro (10%).
The Girassol turbidite channels reservoir was in 1996 the first discovery of Total E&P Angola on this prolific deep offshore Block 17, presenting a good oil quality (32°API) and excellent reservoir characteristics. Jasmim field, laying about 5 km westwards of Girassol was
discovered in 2000, among the other discoveries on Block 17 (Rosa, Lirio, Cravo, Violeta, Orquidea, Dalia, Tulipa, Anturio, Camelia, Perpetua, Zinia, Hortensia and Acacia). The Jasmim field is in communication with Girassol.
Girassol was one of the first Western African deep offshore projects to be put into production, in December 2001. The water depth (about 1400 m), its size (about 15 Km x 10 Km) and unconsolidated sands are at the origin of many technical challenges. Jasmim production started in November 2003.
The role of natural gas as a primary energy source globally is growing rapidly. Over the fiveyear period through 2005, the use of natural gas as primary feedstock for the manufacture of chemicals and petrochemicals is also expected to make some rapid advances. Resource availability, cost and environmental considerations all indicate strong reliance on natural gas in industrial applications and electricity generation. Natural gas is also replacing other traditional fuels in residential, commercial and transportation end uses as well. Therefore natural gas offers the unique opportunity of making a significant contribution to the global program to reduce reliance on high carbon content fuels and thus facilitate compliance to international agreements. The study will therefore be useful to marketing managers, strategic planners, forecasters, new product and business developers, decision makers in the chemical, petroleum and energy industries as well as government agencies, venture capitalists, and those involved in research and development work worldwide.
This paper assesses and evaluates the global demand and utilization of natural gas in the chemical and energy production markets as well as the near term options for its production to meet the forecasted demand. The global marketed supply of natural gas is presented and production of natural gas by region/country, by source (offshore and onshore) and the reserves/production ratio is also discussed. International aspects of natural gas demand are also considered in this paper including forecasts for the 2005-2025 time frame. The effects of foreign and U.S. investment and technology by country and/or region are quantified. Major overseas companies involved in the natural gas business in processing, delivery and other activities are also assessed.
This paper begins with an overview of the natural gas industry. The overview describes the importance of the natural gas industry in relation to the overall global economy including a brief history and important indications for the industry.
The study then goes on to analyze the structure of the natural gas industry and competitive aspects including the driving forces of the industry. Important strategies for staying competitive and important shifts in the industry are assessed. Trade practices of the natural gas industry and the impact of natural gas on the petroleum and power industries are discussed.
This study also includes projections for natural gas production. The largest increase in production is projected for the Middle East—from 8.3 trillion cubic feet (Tcf) in 2001 to 18.8 Tcf in 2025. The smallest increase is projected for the industrialized countries—from 39.3 trillion cubic feet(Tcf) in 2001 to 46.8 Tcf in 2025, an average increase of 0.7 percent per year over the forecast period. Natural gas processing is increasingly becoming a major part of the world natural gas business, as more countries with associated gas look for more economic ways of monetising this resource. This study also presents data on global natural demand by type of processing including natural gas liquids. Some interesting figures of global natural gas reserves and global/regional natural gas consumption are also included in the end of this paper.
Alkylation of isobutane with n-butene is one of the important routes to provide high octane components that can substitute aromatic molecules in gasoline. Traditionally, this route is catalyzed by sulfuric and hydrofluoric acid. Solid acid catalysts have been explored frequently, but have not been commercially implemented to date. This is related to the necessity of frequent regenerations, complex handling of solid catalysts in a liquid-solid system and inherent differences in the reactivity towards n-butene and isobutane. The main drawback in the use of solid catalysts for isobutane alkylation is their rapid deactivation, which so far has prevented their industrial application.
Over the last years, significant progress has been made in this field, leading to the successful development of alkylation technology on a pilot stage. Insight into surface chemistry, the advances in catalyst preparation and the integration with novel reactor technology led to remarkable progress. Catalysts, which surpass the lifetime of sulfuric acid by three orders of magnitude, show potential for economic feasibility based on frequent mild regenerations. This progress has been made possible by enhancing the key quality of the solid catalysts, which is the hydride transfer between the surface bound species and the isobutane.
The lecture will review the potential and limitations of current chemical and engineering concepts and will give an outlook to new developments in isobutane alkylation.
The alkylate produced from isobutane/butene alkylation is an excellent blending component for gasoline. In 2005 the worldwide alkylation capacity amounted to approximately 2 million bpd and it is expected to grow further Figure 1. In fact, due to increasingly strict legislation, the concentration of alkenes and aromatics in the gasoline will be more and more limited in the next years. Additionally, methyl-tertiary-butyl ether (MTBE), a high-octane-number oxygenate, is likely to be prohibited as a gasoline compound. (Figure in full paper) Currently, only liquid acid-catalyzed processes are operated on an industrial scale with approximately equal market shares for processes using sulfuric and hydrofluoric acid. Both of these catalysts suffer from serious disadvantages.
Anhydrous HF is a corrosive and highly toxic liquid with a boiling point close to room temperature. Therefore, refineries with HF alkylation plants are under pressure to install expensive mitigation systems minimizing the dangers of HF leaks. Moreover, authorities in many industrialized countries have ceased to license new HF alkylation plants.
Sulfuric acid is also a corrosive liquid, but not volatile, making its handling easier. Its major disadvantage is the high acid consumption in the alkylation process, which can be as much as 70-100 kg of acid/ton of alkylate. The spent acid contains water and heavy hydrocarbons and has to be regenerated, usually by burning. The cost of such a regenerated acid is about 2-3 times the market price for freshly produced sulfuric acid .
In the last 30 years considerable efforts have been made to replace the existing liquid catalysts by solid materials, which are environmentally benign and easier to handle. Among them the most promising candidates seem to be zeolites.
This paper will focus on the vast deepwater areas of offshore South Africa; areas which require a challenging and expensive exploration effort. Latest exploration activities of Offshore South Africa, combined with a bit of exploration history will be discussed. This would then be compared with worldwide trends concerning deepwater exploration. Africa's important role within this new drive to exploit the world's deepwater hydrocarbon resources is also emphasized. General geology of the offshore basins will briefly be summarized, and the talk will coclude with the latest resource estimates of South Africa's deepwater areas.
During the past 30 years, exploration of the Mesozoic basins of offshore South Africa was generally restricted landwards of the 200m isobath, with only a few wells exploring the Orange Basin on the West Coast in water depths deeper than 400m. Off the South Coast these rigs could only manage in water depths of up to 300m maximum. The strong Agulhas current and adverse weather conditions imposed restrictions on the use of the existing semisubmersibles.
The first offshore well in 1968 discovered the Superior gas field in the Pletmos Basin, which is a sub-basin of the Outeniqua Basin off the South Coast. Subsequently, most of the offshore exploration was then focussed in the Bredasdorp Basin, which led to production of the F-A, EM and satellite gas fields in 1992, which have been feeding the synfuel plant at Mossel Bay. First oil production from the Oribi oilfield followed in May 1997, a deep marine basin floor channel and fan complex (bff complex), and production was increased when the Sable oil, gas and condensate field came onstream in mid-2003.
The Orange Basin is defined by the extent of a sedimentary wedge that occupies about 150 000 km2 off the southwestern coast of Africa, and is more than 8 km thick in places. Although the basin is sparsely drilled with only 40 wells, most of which tested the shallow water areas, results thus far have been extremely encouraging. Two gas fields (Ibhubesi in South Africa, and Kudu in Namibia) with multi-TCF potential have been discovered within the younger geology, while the A-J1 well yielded an oil discovery in some of the oldest sedimentary fill.
The Ibhubesi gas field has recently been defined by Forest Exploration International, through appraisal drilling in the area of the original A-K1 discovery well. The tested wells in this field yielded a high combined flow rate of dry gas and condensate. Analysis of 2D and 3D seismic surveys in the area has defined many new prospects and justifies the extension of this play for some distance to the north.
The Durban Basin remains under-explored with only 4 wells testing the offshore areas close to shore, all of which were non-commercial.
Studies of oil discoveries made during the nineties indicate that giant oil discoveries are more frequently found in the deepwater areas of the world compared with the shallower water regions.
The purpose of a hydrocracker is to convert vacuum gas oil and demetalized oil (DMO) to naphtha and diesel. Saudi Aramco has two total conversion hydrocrackers which operate at very high pressures. The hydrocracking catalyst plays an important role in a hydrocracking unit and its selection is very critical to the success of hydrocracker's performance. The premature failure of the previous hydrocracking catalyst in one of Saudi Aramco hydrocrackers intensifies the importance of hydrocracking catalyst selection. Thus Saudi Aramco develops an intensive catalyst selection program to safeguard the catalyst selection for refining catalytic processes.
This paper summarizes hydrocracking catalyst selection process which includes proposal evaluation, pilot plant testing program and economic evaluation. Detailed evaluation results including pilot plant test results and economic evaluation will be reported in the presentation.
The hydrocracking technology plays an essential role in the world's refining economics by upgrading heavier and lower value vacuum gas oil (VGO), demetalized oil (DMO), or residuum into lighter and higher value naphtha and diesel. Hydrocracking catalysts selection is very critical to the success of the hydrocracker performance. Therefore, a refiner should implement a proper procedure in order to safeguard the catalyst selection to meet most of the operating objectives. The pre-mature failure of the previous hydrocracking catalyst in one of Saudi Aramco's (SA) refineries was the compelling starting point for developing a well structured procedure for selecting refining process catalysts.
Saudi Aramco Standard for Refining Process Catalyst Selection
Saudi Aramco has developed a standard to establish requirements for selection and quality assurance/quality control (QA/QC) of refining process catalysts. The catalyst selection procedure starts with development of the technical package and performance guarantee which we send to vendors to solicit catalyst proposals, and initial screening of all technical proposals by benchmarking them against the refinery desired criteria. The initial evaluation rules out some inappropriate proposals. If necessary, the selection process includes pilot plant (P/P) testing of potential catalysts. The P/P testing is conducted under the same operating conditions to mimic the commercial operations. In addition, the selection process includes a survey on users to get their feedback on performance of the proposed catalyst systems. Finally, an economic evaluation on the technically acceptable catalyst systems, together with the performance guarantee and users' comments, will determine the winning catalyst system. The standard also indicates that QA/QC tests on a pre-delivery sample are required before the catalyst is shipped to the refinery. If necessary the performance tests can be conducted during the catalyst cycle to validate performance guarantees. Any deviation from the standard will require a waiver from the appropriate authority.
Hydrocracker Catalyst Selection
Hydrocracker Unit Process Description
The hydrocracker unit (HCU) is a single stage, series flow unit with two parallel trains. Each train encompasses two treating reactors and two cracking reactors with a steam generator in between to recover waste heat and control the inlet temperature of the first cracking reactor. The fractionator bottom is sent to the vacuum tower in the crude unit to eliminate heavy polynuclear aromatics (HPNA) and is recycled back to the first reactor.