1 April 2005
No lack of sophistication in emerging market
By Cuitlahuac Picasso Blanquel, Carlos E. Uribe Blanco, Héctor Pérez Santiago, Casimiro González Malcom, Dinorah Díaz Castellanos, and Jesica Martínez Gutiérrez
An important benefit of a real-time monitoring and control system is it allows operators to know the actual conditions of oil and gas in each peripheral site.
Likewise, it can perform interlock controls in a remote case, measure oil and gas for each peripheral site, and have the capacity to shut down oil wells in case of emergency to prevent costly ecological damage from spilled oil.
It's imperative to know the parameters of offshore hydrocarbon production to ascertain productivity profiles of the wells and the wells behavior in general.
Parameters like pressure, temperature, flow, water in oil analysis, and others allow us to know and control the hydrocarbons production.
At the southwest Gulf of Mexico location, one problem is we now record much information manually over noncontiguous periods. Major disadvantages are weather, transportation, limited mobility, and the fact that platforms are located 20 to 30 kilometers offshore.
When advances in computer information systems, data acquisition, wireless communications, protocols, and instrumentation work in this type of project, it must take place such that oil productivity and human safety take precedent.
The goal was to leverage the new technologies to establish a system of remote control and monitoring (SRCM) for offshore platforms. We would apply sturdy hardware, man machine software, and reliable communications to connect the main platform with the remote sites. The connection mechanisms must acquire the data in real time and determine the behavior and life expectancy of wells.
We wanted an unmanned system that would protect the environment, extend the life of the production wells, and ensure the safety of personnel when present.
Development of the specification
In order to establish the SRCM architecture:
1. We considered the wells located in the satellite marine platforms are 12 years old and are in a state of decline.
2. We considered the original process diagrams, pressure, flows, and temperature numbers for the SRCM.
3. We considered the current range of numbers.
4. We considered manual reports from the operator logbooks as well the operators' expertise.
The architecture broke out into these divisions: supervision and control station; wireless communication; process controller; high speed fieldbuses to connect the process controller and the intelligent instrumentation with built in processing and self-diagnosis; and an energy system using solar cells.
The equipment of the central controller connects to the satellite platforms by wireless wide area network (WAN). It has the high speed and bandwidth that enable monitoring and control, and the instrumentation has its diagnostics.
The SRCM is open, safe, upgradeable, interoperable, and portable.
The client-server architecture has full interconnectivity and features a redundant server tolerant to faults, workstations, printers, a local area network (LAN), and hardware for wireless network connectivity.
As to the man machine interface functions (MMI), we wanted real-time processing of the acquired data displayed and organized so the operator can work through a graphical interface based on menus, dialogue windows, icons, tool tips, toolbar, status bar, special keys, and help windows.
The MMI had to monitor process status variables and provide profile and behavior of ongoing hydrocarbon extraction.
Communication is secure
The remote-process units (RPU) are located on the different platforms and must seamlessly connect to the master station and conform to the overall SRCM system.
Based on a fundamental analysis of the information requirements, as well as the necessities of low cost bandwidth, spread spectrum technology offers the best advantages. It uses higher band amplitudes like 2.4-2.4835 gigahertz (GHz), 5.15-5.35 GHz, and 5.725-5.825 GHz, which do not require licensing and also avoid interference with normal radio frequencies.
The frequencies are secure and readily accept a variety of external antennas that improve coverage and quality of communication.
The wireless network that connects the master station with the process controllers must have a transmission speed of 2 to 11 Mbps, using TCP/IP protocol.
The communications system must have a reliability and availability of 99%. The system demands are high and must overcome the marine environment, curvature of the earth, and loss of signal caused by distances between the satellite platforms and central control.
The required equipment must work in marine environments, high humidity, and high temperatures.
Process controllers are also at each remote site. They carry out data processing chores as well as maintain the connection with central control.
Our proposal dictates hardware infrastructure and modular software that embraces redundant process control is fault tolerant, and that allows for fieldbus architecture that uses Profibus DP/PA or Foundation Fieldbus technology.
Specifically, the RPU will be responsible for processing collected data, executing control algorithms, and continuously monitoring the instruments, sensors, and actuators of the process.
All the equipment should be explosion proof or intrinsically safe depending on the technology, Profibus DP or Fieldbus H1.
The RPU modules will size out according to the number of signals handled by the process, probably 60 signals per site and seven remote sites.
The main and redundant RPUs will have backup power supplies, CPU's, and communication cards for connection to the master station. According to the number of indicated signals, five field networks will go in each site. The five networks are necessary to comply with the intrinsic safety limitations of energy.
For their connectivity to the network WAN, the RPU must have a card with RJ45 interface and support transmission speeds of 10/100 Mbps in agreement with the standards IEEE 802.3 and IEEE 802.3.
Equipment cases and envelops at each RPU will have to exist in a highly corrosive environment and endure heavy winds.
Which fieldbus network?
We analyzed the different field networks Profibus DP/PA or Foundation Fieldbus. Strong competition between instrumentation manufacturers and field devices exists, and they both propose their own technology.
We took into consideration manufacturers' information that networks come in three categories: simple sensors, process devices, and high-speed networks.
Simple sensors are for field and plant floor operations, and they include AS-i bus, Fieldbus, Bitbus, and Worldfip. Some examples are proximity sensors, optical sensors, switches, on/off valves, and indicators. For Worldfip, it is possible to use control loops between sensors and actuators.
For networks where there are processed devices, we see field networks as DeviceNet, Profibus DP, Fieldbus H1, Interbus, Controller Area Network (CAN), ControlNet, and Lonworks. Each one of these technologies has its special area of expertise and primary usage, like automotive applications with real time response, others apply to processes, and others for machines automated tools. These networks work with diagnosis in the instruments and the handling of multiple masters and slaves.
Finally, at the high-speed end, networks can be Profibus DP/PA, Foundation Fieldbus HSE, and Industrial Ethernet. These networks allow reduced wiring and apply operational controls to the instruments. Each network segment can have a tasks administrator for all the devices.
The instruments specified for each satellite platform are intelligent—they process and send information about the variable with which it is concerned and about the health and status of the instrument itself.
The instrumentation the project considered for each platform included:
- Bulbs of resistance (RTDs) and thermo wells
- Level controller displacement
- Pressure interrupting
- Pressure gauges
- Measurers of mass flow
- Transmitters of pressure, differential pressure, and multi-variable
- Temperature transmitters
- Orifice plates
- Pressure valve controllers
- Actuators for valves of blockade operated by solenoid
- Safety and relief valves
- Control valves
- Ultrasonic measurement
- Local pressure gauges
- Pressure controllers
Given the risky conditions in the process of hydrocarbon extraction using marine platforms, it is important to consider the safety standards and the criteria of operation to be able to carry out the automation of the measurement of hydrocarbon production.
The process breaks down into three functions. The first function is to acquire and supervise the variables relating to the behavior of the hydrocarbon extraction process. This primarily relates to the pressure, flow, and temperature variables.
The second function is the measurement of hydrocarbon production. This area includes the remote-control opening and closing of valves to let the hydrocarbons of the production head go to the test head and then to the separating tank.
To measure the productivity of the wells, the package considers the mass flow rate for the produced oil and ultrasonically measures the gas. Currently the flow measurement uses orifice plates, which allows the interchange in both flows of oil and gas. This measurement stays local in order to register the cost graphically, so the operators get a dashboard view of the operation on the satellite platforms.
The third function is the remote closing of wells due to environmental emergencies or maintenance or for production control. The shutoffs can take place by individual well, by individual platform, or by an entire oil field.
Solar cell based energy
On marine platforms electricity is not plentiful, and so generating it with solar cells is an alternative.
Due to the nature of the working surroundings, the electrical classification is NEC Class 1, Division 2, Group D or IEC 79-10 Zone 1, which is to say explosion proof or intrinsically safe.
To meet process requirements, the energy handled by the equipment must be less than 180 micro joules. According to the manufacturer's information, the power consumption average by each instrument is 400 milliwatts; if every fieldbus network handles 15 instruments and every platform has five field networks, then 30 watts is adequate for each platform's instruments.
Additionally, the energy consumption of the process controller (RPU) is 250 watts. Altogether 280 watts are required to power up the equipment in every marine platform.
Considering these calculations and previous design experience, a power supply that provides 500 watts is required. The energy system needed has two solar cell banks, two battery banks, and a regulating-loader.
The primary innovation on this project is the wireless offshore technology, which leverages a WAN architecture. Coming in a close second is the use of fieldbuses networks that generate self diagnostic information about the instruments' operation.
The SRCM turns out to be an indispensable tool that minimizes the risks in the process and saves travel expense and peril by reducing trips to platforms.
It is important to consider the implantation of a SRCM in marine platforms to reduce labor costs, ensure timely completion of tasks, provide information about well production, and generate reports and statistics.
Behind the byline
Six engineers wrote this paper about a Pemex (Petroleos Mexicanos) project in the Gulf of Mexico. They are Cuitlahuac Picasso Blanquel (firstname.lastname@example.org), Carlos E. Uribe Blanco (email@example.com), Héctor Pérez Santiago (firstname.lastname@example.org), Casimiro González Malcom (email@example.com), Dinorah Díaz Castellanos (firstname.lastname@example.org), and Jesica Martínez Gutiérrez (email@example.com). They presented a paper on this Pemex marine project at ISA 2004 in Houston.
Foreign investment in Mexico soars
Foreign direct investment in Mexico rose 46% last year, the Economy Ministry reported.
Dow Jones Newswires reported the ministry said the total included $7.99 billion in new investment and $2.47 billion in reinvested profits.
More than half of the total investment went into the manufacturing sector and close to 30% into financial services. The leading source of investment was the U.S. with 48%, followed by Spain with 34.7%.
Last year's foreign direct investment will probably be more than enough to cover the current account deficit.
Last year's foreign direct investment matches the $16.6 billion in remittances that Mexicans living abroad sent home last year.
Remittances have become an increasingly important source of foreign currency in Mexico, overtaking tourism and approaching crude oil.
Mexico earned $10.8 billion last year from tourism and more than $21 billion from exports of crude oil.
Deep water oil seeks cash, technology
Mexico's efforts to tap deep water oil reserves will likely require about $200 billion in investment over 20 years, a BP Plc official said.
The Wall Street Journal reported Chris Sladen, vice president of exploration and production for BP Mexico said, "How much money is needed depends on the requirements of Mexico going forward in production."
Speaking at an event sponsored by Mexican state oil monopoly Petroleos Mexicanos (Pemex), Sladen said other companies have been extremely successful in reaching deep water reserves on the U.S. side of the Gulf of Mexico, and those efforts have been collaborative.
Sladen and other representatives of multinational oil companies said a joint-effort is the best way for Pemex to successfully harvest deep water crude deposits.
Pemex reckons it has about 45 billion barrels of oil below deep water in the Gulf, but officials have said they will need to form alliances with other companies to acquire the technology and experience necessary to explore and exploit the resource. That requires legal changes in Mexico, where energy laws prohibit Pemex from granting oil and gas concessions or forming upstream joint-ventures.
Given the high financial stakes of the deep water project, the format of the multiple-service contracts Pemex has awarded to produce natural gas from proven reserves wouldn't offer the same sort of rewards in deep water. A joint-venture might be necessary to guarantee returns on investment for the multinationals.
"We have to talk to the oil companies to see how they want to do it. There's no perfect scheme," said Rafael Bracho, deputy head of finance at Pemex.
Last November, Pemex struck oil at a depth of 680 meters. Pemex contracted Diamond Offshore Drilling to drill that well.
"If you look at the U.S. Gulf, it's all provided by private contracts. There's a learning curve in deep water," said Andrew Gould, chief executive of oil services company Schlumberger Ltd.
By bringing several multinationals on to the deep water project, Pemex can tap into the best and brightest of the industry, private sector experts say.
"We've had a lot of discussions with Pemex. There's a lot of opportunity for us to work together. Geology doesn't know country borders," said Lew Watts, senior vice president of innovation and marketing for Houston-based services company Halliburton.