Oil Processing Facilities Research Articles

Confiabilidad Operativa de Sistemas para Compresión de Gas y Generación Eléctrica en Complejos Petroleros

This paper presents a study that compares operative results for three technological alternatives to produce electricity and compress gas in offshore crude oil processing facilities to be installed in Mexico. The comparison of alternatives is made based on system reliability estimations by using the “reliability block diagram” method. The fundamental concepts of the systems reliability theory are pointed out, and the reliability model is defined as a parallel arrangement with redundancy in passive reserve and without maintenance for any component. Likewise, the alternatives, and the analyzed operative scenarios are described, including the block diagrams and reliability results for each option. The results of the study show that using electrical motors to compress gas and internal combustion engines to produce electricity is more reliable than using gas turbines.

Characterization of Groundwater Contamination Using Factor Analysis in the Niger Delta (Nigeria)

The present work examines the results of factor analysis performed on major ions and total hydrocarbon content (THC) from hydrochemical studies over Benin formation aquifer of the Niger Delta Basin, Nigeria. The dominant cations are Na(50%)>Mg(27%)>Ca(23%) and Cl (96%) as the dominant anion. Five major factors were found to explain the source of the ions and THC in the groundwater. Generally, Factors 1 (EC, Ca2+, K+, HCO3−, and SO42−) and 4 (Mg2+, Na+, and CI) are mainly due to ion exchange sea water intrusion and effluent water disposal near oil processing facilities. Factor 2 (Fe and Mn) is attributed to geogenic sources while Factor 3 (temperature, pH, dissolved oxygen, and THC) is due to effluent water disposal, leakages of crude oil pipelines, storage facilities, and indiscriminate disposal of waste. Factor 5 (NO3) is attributed to the disposal of human and domestic wastes into the environment.

A Fifteen Year Record of Global Natural Gas Flaring Derived from Satellite Data

We have produced annual estimates of national and global gas flaring and gas flaring efficiency from 1994 through 2008 using low light imaging data acquired by the Defense Meteorological Satellite Program (DMSP). Gas flaring is a widely used practice for the disposal of associated gas in oil production and processing facilities where there is insufficient infrastructure for utilization of the gas (primarily methane). Improved utilization of the gas is key to reducing global carbon emissions to the atmosphere. The DMSP estimates of flared gas volume are based on a calibration developed with a pooled set of reported national gas flaring volumes and data from individual flares. Flaring efficiency was calculated as the volume of flared gas per barrel of crude oil produced. Global gas flaring has remained largely stable over the past fifteen years, in the range of 140 to 170 billion cubic meters (BCM). Global flaring efficiency was in the seven to eight cubic meters per barrel from 1994 to 2005 and declined to 5.6 m3 per barrel by 2008. The 2008 gas flaring estimate of 139 BCM represents 21% of the natural gas consumption of the USA with a potential retail market value of $68 billion. The 2008 flaring added more than 278 million metric tons of carbon dioxide equivalent (CO2e) into the atmosphere. The DMSP estimated gas flaring volumes indicate that global gas flaring has declined by 19% since 2005, led by gas flaring reductions in Russia and Nigeria, the two countries with the highest gas flaring levels. The flaring efficiency of both Russia and Nigeria improved from 2005 to 2008, suggesting that the reductions in gas flaring are likely the result of either improved utilization of the gas, reinjection, or direct venting of gas into the atmosphere, although the effect of uncertainties in the satellite data cannot be ruled out. It is anticipated that the capability to estimate gas flaring volumes based on satellite data will spur improved utilization of gas that was simply burnt as waste in previous years.

Distinguishing between Natural Crude Oil Seepage and Anthropogenic Petroleum Hydrocarbons in Soils at a Crude Oil Processing Facility, Coastal California

Crude oil from offshore deposits in the Miocene Monterey Formation is commonly processed at facilities along the California coast. This formation is known for natural crude oil seepage (NCS), manifested at a California oil and gas processing facility (the site) as small pools on the ground surface, discharge from an adjacent bluff, and as free product in a hand-dug well. In addition, hydrocarbons are also present in site soils due to historical leaks at the facility, referred to here as anthropogenic petroleum hydrocarbons (APH). An investigation using gas chromatography/mass spectrometry (GC/MS) and isotopic techniques compared the chemical signatures of NCS and APH in soil to determine if it was possible to separate the populations. The NCS samples have a well-developed unresolved complex mixture (UCM) compared to the APH samples, yet lighter polycyclic aromatic hydrocarbons (PAHs) in the NCS are more numerous and in higher concentrations than in the APH samples, possibly indicating a different degradation trajectory. Other useful discriminatory parameters appear to be the greater abundance of: tricyclic terpanes (in NCS), C27-diasteranes (in NCS), C28-ergosteranes (in APH), C27- and C29-monoaromatic steranes (in NCS), and C20- and C21-triaromatic steranes (in NCS). Other parameters, e.g., δ13C and δ D, had no apparent discriminatory power. This study demonstrates that NCS appears chemically distinct from APH at this site. However, it would be necessary to obtain empirical evidence for other sites with similar concerns due to vagaries in facility-specific sources, degradation rates, etc.

Practical Method for Numerical Evaluation of Parameters of Pool Fires in Oil Pipeline Networks

Practical Method for Numerical Evaluation of Parameters of Pool Fires in Oil Pipeline NetworksThis paper presents a method for numerical evaluation of parameters of flammable liquid pool fires caused by storage tank or pipeline failures. The method may be useful for specialists working in oil and gas, and chemical industries. It was successfully applied in fire safety analysis of Russian gas and oil processing facilities.

Liquid Salt Applications and Molten Salt Reactors

In the last 5 years, there has been a rapid growth in interest in the use of high-temperature (700 to 1000°C) molten and liquid fluoride salts as coolants and for other functions in nuclear systems. This interest is a consequence of new applications for high-temperature heat and the development of new reactor concepts. These salts have melting points between 350 and 500oC; thus, they are of use only in high-temperature systems. Nitrate salts with a peak operating temperature of ~600°C are the highest-temperature commercial liquid coolant available today; thus, the development of higher-temperature fluoride salts as coolants opens new nuclear and non-nuclear applications. These salts are being considered for intermediate heat transport loops between all types of hightemperature reactors (helium and salt cooled) and hydrogen production systems, oil refineries, and shale oil processing facilities. Historically, steam cycles with temperature limits of ~550°C have been the only efficient method to convert heat to electricity. This limitation produced few incentives to develop high-temperature reactors for electricity production. However, recent advances in Brayton gas-turbine technology now make it possible to convert higher-temperature heat efficiently into electricity and thus have created the enabling technology for more efficient cost-effective high-temperature reactors. The near-term advanced high-temperature reactor (AHTR) uses a graphite-matrix coated-particle fuel and a liquid salt coolant. There is the longer-term potential of a liquid-salt-cooled fast reactor (LSFR) that uses metal-clad fuel and a liquid salt coolant. The molten salt reactor (MSR), with the fuel dissolved in the molten salt coolant, is receiving increased attention because of (1) the advancing salt-coolant technology and Brayton cycles that improve the economics, (2) advances in salt chemistry that enable the development of fast-spectrum MSRs with the safety advantages of large negative void coefficients, and (3) the interest in actinide burning where MSRs avoid the need to fabricate fuel of highly active actinides. Last, there is a developing interest in liquid-wall fusion machines with much higher power densities than solid-wall fusion machines.

Engineering and construction projects for oil and gas processing facilities: Contracting, uncertainty and the economics of information

The amount of oil and gas processing capacity required to meet demand during the next 20 years is more than twice the amount realised during the last decades. Engineering and Construction contractors (ECs) play a key role in the development and implementation of Large Engineering and Construction Projects (LECPs) for these facilities. We examine the characteristics of LECPs, demand and supply of the contracting market and the strategies traditionally adopted by owners to contract out the development and implementation of these projects to ECs. We demonstrate that these traditional strategies are not longer effective, in the current ‘sellers market’, to mitigate the oligopolistic economic inefficiencies. As the ‘overheating’ of the contracting market is expected to continue for a considerable period of time, alternative contracting strategies are required. Contract theory, particularly the economics of information on LECPs, indicates how alternative contracting strategies can be used to overcome economic inefficiencies. The effective use of these alternative strategies requires increased owner involvement and their effectiveness is contingent upon owner competency and ECs acting as the owner's agent rather than its adversary. This will require an organisational and behavioural change process for both owners and ECs.

DETERMINATION OF AFLATOXIN CONTAMINATION IN OLIVES BY IMMUNOAFFINITY COLUMN USING HIGH‐PERFORMANCE LIQUID CHROMATOGRAPHY

ABSTRACT Eighty‐two whole black olive samples gathered from six different olive oil processing facilities were surveyed to determine levels of aflatoxins using immunoaffinity column extraction and reversed‐phase high‐performance liquid chromatography. Two different analytical procedures adopted for the analysis of aflatoxins were investigated for their suitability by spiking the blank olive samples with five different known levels of aflatoxins to determine which one had higher recovery rates. Although some of the olive samples had been exposed to adverse conditions, such as rain and high temperatures, none were found to contain aflatoxins at the determined detection limit. Although the samples were kept in high relative humidity (75%) and high temperature (30C) for 3 months and were tested at 1‐month intervals, no aflatoxins were detected. In addition, the olives were inoculated on a potato dextrose agar medium and incubated for 7 days at 25C to characterize the microflora. Because there is no evidence of aflatoxins in fresh whole olives, the next step of processing the contaminated olives into olive oils and testing them for the aflatoxins was not pursued.

INCREASED OIL PRODUCTION BY ADVANCED CONTROL OF RECEIVING FACILITIES

Slug flow from wells or multiphase flow lines from subsea satellite fields is one major disturbance at offshore oil and gas processing facilities. Slugging is an undesirable flow pattern with liquid blockages that can occur in multiphase flow lines transporting both gas and liquid. The original contribution in this paper is the successful application of advanced control for the inlet facilities, where active slug control for two 11.7 km long multiphase flow lines is combined with model predictive control to handle slugs entering the inlet separators.

Preliminary Evaluation of a White-Rot Fungal Reactor in the Treatment of a Waste Oil–Recycling Wastewater

ABSTRACT An investigation of the treatment of a complex waste oil–recycling hydrocarbon wastewater was made by employing white-rot fungal strains immobilized in a pinewood chip-packed reactor. The reactor was operated in sequencing batch mode. The fungal reactor was evaluated in a preliminary bench-scale reactor followed by intermediate-scale operation. Substantial chemical oxygen demand (COD) reduction (> 96% in 48-h batch cycles) and removal of specific influent compound constituents, alkanes (n-C8, n-C10–C12) and aromatic compound (o-xylene), was shown in diluted and undiluted (COD > 37 g L−1) influent. Industrial application of the fungal reactor was evaluated in a 14-m3 pilot plant erected on-site at a waste oil–processing facility. The scale-up implication and optimization of the field plant is discussed in relation to the process-monitoring programme.

Detection of Precipitation in Pipelines

One of the major unsolved complex problems confronting the petroleum and chemical industries at present is the untimely deposition of heavy organic and other solids dissolved or suspended in the fluid flow systems. The production, transportation, and processing of petroleum can be significantly affected by flocculation and deposition of such compounds in the course of industrial processing systems, including transfer conduits, reactors, and refineries and upgrading equipment, with devastating economic consequences. Heavy organics such as paraffin, wax, resin, asphaltene, diamondoid, mercaptdans, and organometallic compounds can precipitate out of the crude oil solution due to various forces causing blockage in the oil reservoir, well, pipeline, and in the oil production and processing facilities. It is important to producers that the potential organic deposition can be predicted so that the production strategy can be designed to prevent, if possible, or mitigate this problem. Cleaning the pipeline has a common commercial term, pigging. Early detection of precipitation can reduce pigging and, in turn, the maintenance cost considerably. Prediction of why and when precipitations occur has gained much interest in recent years. Most studies focus on the chemical behavior of the crude oil and its contamination. A nonintrusive instrumentation technique for on-line inspection that can yield as much detailed information about the interior of the pipe as possible is highly desirable. In this article, the detection of asphaltene and paraffin wax is studied using various techniques. The techniques include the use of solid detection system by light transmittance measurement for asphaltene detection, the use of photodiode for light transmittance measurement for liquid wax, the use of ultrasound and strain gauge for detecting solid wax.

Optimization of Process Parameters for Glycol Unit to Mitigate the Emission of BTEX/VOCs

Recent developments in environmental regulations on the emissions of aromatic compounds including benzene, toluene, ethyl benzene and xylene isomers (BTEX) and other volatile organic compounds (VOCs) have made these emissions a major concern in the natural gas industry. In particular, one of the sources of emissions is glycol dehydration units. During the dehydration of natural gas, the BTEX and VOC compounds in it are absorbed by the glycol solvent, and subsequently emitted to the atmosphere during the thermal regeneration of glycol. As a result, quantification and means of reduction and ultimately elimination of these emissions is gaining importance in the industry. This problem requires careful attention during the design phase. The environmental considerations mentioned above are increasingly driving the selection and operation of process alternatives to reduce the BTEX/VOCs emissions to the atmosphere. This paper focuses on the glycol dehydration unit for one of the onshore oil and gas processing facilities in Abu Dhabi operated by Abu Dhabi Company for Onshore Oil Operations (ADCO). Firstly, the BTEX/VOCs emission levels vented out to atmosphere are quantified, and a description given of the sampling/measurement technique. Secondly, the process parameters associated with all major equipments in the glycol dehydration unit, i.e. the absorber, the flash tank, and the regenerator that may lead to the reduction in BTEX/VOC emissions, are optimized. The optimization study involves building a process simulation model based on actual design data/parameters provided by the glycol unit vendor and verified by operational data.

ニーワットアルギャラン油田の開発

Abu Dhabi Oil Co., Ltd. (ADOC) is currently operating three oil fields; Mubarraz, Umm Al-Anbar and Neewat Al-Ghalan (GA) Fields. The oil production of Mubarraz Field commenced in 1973 and an artificial lift with ESP (electrical submersible pump) was applied. Umm Al-Anbar Field initiated the oil production in 1989 and one of EOR methods; a vaporized gas miscible drive was applied to increase an oil recovery. Neewat Al-Ghalan Field is located in the southern part of the Arabian Gulf about 100km off the coast of Abu Dhabi, U.A.E., between Umm Al-Anbar Field and Mubarraz Island where ADOC has oil processing, storage, loading and utility facilities. GA Field is marginal to be developed from its reservoir characteristics, low OOIP and so on. The development of the field became feasible by applying the vaporized gas miscible drive for achieving higher oil recovery, and utilizing the existing facilities in Umm Al-Anbar Field and Mubarraz Island. The development plan was established and the development works commenced in 1993. It has been completed in two years as scheduled and the production commenced in June 1995.This report summarizes the development of Neewat Al-Ghalan Field with presenting its exploration, field outline, development plan, development works and both production and injection performances. It also describes a sour gas injection project, which is undergoing in order to solve an environmental protection issue.

Harmonics at the utility industrial interface: a real world example

This paper describes the application of 5th and 7th harmonic filters to an oil gathering and processing facility substation to reduce total harmonic voltage distortion on the local utility system to within IEEE Standard 519 recommended limits. The example oil company's Beaver Creek Facility consists of producing fields and a gas processing plant, located in central Wyoming near the town of Riverton. Electrical power for the plant and field is provided by a small electric cooperative which serves and meters the facility at 69 kV. In addition, gas powered turbines provide cogenerated power. The use of the six-pulse variable speed drives coupled with the addition of power factor correction capacitors created a situation in which harmonic distortion levels on the local utility's system exceeded recommended limits. This prompted the installation of 5th and 7th harmonic filters at the Beaver Creek substation.

TRIALS OF A MULTIPHASE FLOW METER ON PRODUCTION PIPELINES FROM OIL WELLS

This paper describes trials of a new multiphase flow meter (MFM) on the Vicksburg offshore production platform and at the oil processing facilities on Thevenard Island. The flow meter is based on two specialised gamma-ray transmission gauges mounted on a pipe carrying the full flow of oil, water and gas.Two MFMs were used in both trials, one mounted on a vertical (up flow), and the other on a horizontal, section of a pipeline linking the test manifold to the test separator. Measurements were made on flows of oil/water/gas mixtures from each well, and on combined flows of different pairs of wells.The r.m.s. difference between the flow rates determined by the MFM and by the separator output meter was determined by least squares regression. For the Vicksburg trial, the ratio of r.m.s. difference and mean flow rate was 8.9 per cent for oil, 5.6 per cent for water, 5.2 per cent for liquids, and 8.2 per cent for gas for flows in the vertical pipeline and slightly larger for flows in the horizontal pipeline. For the Thevenard Island trial, the preliminary results for flows in the vertical pipeline show the ratio to be 6.8 per cent for oil, 6.0 per cent for water, 3.4 per cent for liquids, and 5.9 per cent for water cut.

Hydrocarbon concentrations in sediments and clams (Rangia cuneata) in Laguna de Pom, Mexico.

Laguna de Pom is a coastal lagoon within the Laguna de Terminos system in southern Gulf of Mexico. It belongs to the Grijalva-Usumacinta basin, and is located between 18{degrees} 33{prime} and 18{degrees} 38{prime} north latitude and 92{degrees} 01{prime} and 92{degrees} 14{prime} west longitude, in the Coastal Plain physiographic Province of the Gulf. It is ellipsoidal and approximately 10 km long, with a surface area of 5,200 ha and a mean depth of 1.5 m. Water salinity and temperature ranges are 0 to 13 {per_thousand} and 25{degrees} to 31{degrees}C, respectively. Benthic macrofauna is dominated by bivalves such as the clams Rangia cuneata, R. flexuosa, and Polymesoda carolineana. These clams provide the basis of an artisanal fishery, which is the main economic activity in the region. The presence of several oil-processing facilities around the lagoon is very conspicuous, which together with decreasing yields has created social conflicts, with the fishermen blaming the mexican state oil company (PEMEX) for the decrease in the clam population. This work aims to determine if the concentration of hydrocarbons in the clams (R. cuneata) and sediments of Laguna de Pom are responsible for the declining clam fishery. 11 refs., 4 figs., 2 tabs.

Use of Unmanned Platforms in an Offshore Environment

Summary This paper summarizes operating experience with unmanned productionfacilities 100 miles [160 km] offshore in the South China Sea. productionfacilities 100 miles [160 km] offshore in the South China Sea. The 11 unmannedsatellite platforms currently in operation produce to a manned centralprocessing platform (CPP), where major processing and compression facilitiesare concentrated. The evolutionary development of this central/satelliteconcept provided significant savings in capital and operation cost. Introduction Esso Production Malaysia Inc. (EPMI) has petroleum operations offshoresoutheast Asia in the South China Sea, as shown in Fig. 1. Approximately 100miles [160 km] off the coast of peninsular Malaysia, producing fields are inwater depths of about 200 ft [60 m]. EPMI, acting as a contractor to PetroliamNatl. Bhd. (Malaysia's national oil company), started oil Petroliam Natl. Bhd.(Malaysia's national oil company), started oil production in peninsularMalaysia in 1978. The 24 off-shore platforms form production in peninsularMalaysia in 1978. The 24 off-shore platforms form a network capable ofproducing more than 350,000 B/D [55.6x 10 3 m3/d] oil through a subseatrunkline to an onshore crude stabilization and exporting terminal. Theplatforms can be divided into three types: CPP's and manned and unmannedsatellite platforms. As Fig. 2 shows, until mid-1988, there were eight CPP's, four manned satellites, and nine unmanned satellites; a pumping platformconnected to a manned satellite by a bridge is not pumping platform connectedto a manned satellite by a bridge is not included in this total. Three moreplatforms (one CPP and two unmanned satellites) were installed in late 1988 and1989 (not shown in Fig. 2). Distances between the satellites and the CPP's varyfrom l to 9 miles [1.6 to 14.5 km]. The CPP's act as the focal points for field development and have oil-water-, and gas-processing facilities. Oil-processing facilities include two or threestages of crude separation, after which the dewatered crude is pumped to shoreby the pumping platform. Produced water is treated to remove residual oilbefore being discharged to the sea. Gas-processing facilities to meetgas-injection, gas-lift, and gas-sales requirements include compressionturbomachinery and dehydration systems. Other utility systems areturbine-powered generators, freshwater-making units, instrument-aircompressors, and gas-flaring facilities. Manned satellites were an early development concept. This type of platform, where facilities are operated continuously, offered an economical platform, where facilities are operated continuously, offered an economical means ofproduction and training before unmanned satellites evolved. Facilities on theseplatforms include one stage of crude separation for metering purposes, equipment to treat produced water, and utility systems similar to those on theCPP's. These platforms do not have crude-pumping facilities and require minimalstaffing. Unmanned satellites were introduced as additional offshore operatingexperience was gained. Facilities are kept to a minimum to allow unattendedoperations. The current generation of unmanned platforms has remotewell-testing equipment, a test separator, and air compressors. Subsea cablesprovide electrical power and remote control. Unmanned Satellites First introduced in 1979, unmanned satellites became increasingly importantin later field developments. They provide a cost-effective means for developingand producing major and minor fields. Their usefulness is further substantiatedby very good operating experience, especially reduced operating costs andstaffing, compared with the initial manned satellites. The benefits that unmanned satellites offer are best illustrated by thedevelopment of the Guntong, Tabu, and Palas oil fields. Fig. 3 shows the sevenplatforms required for the initial development of these fields. This initialdevelopment involved installing a CPP--Guntong A--and four unmannedplatforms--Tabu A, Palas A, and Guntong B and C--all of which produce toplatforms--Tabu A, Palas A, and Guntong B and C--all of which produce toGuntong A. As Fig. 3 shows, two other platforms are planned for the future. Production from these fields started in late 1985 and early 1986. Developing these fields with all manned satellites, with centralized oil, water, and gas processing at Guntong A, would have required a capitalinvestment of about $440 million, a crew of 224, and $27 million in annualoperating costs. By comparison, the use of unmanned satellites requires acapital investment of about $300 million, a crew of 124, and about $20 millionannually to operate all the platforms. Savings of about $140 million in capitalcost and $7 million annually in operating cost can therefore be attributed tothis concept. Crews are reduced by 100 because of the concentration ofexperienced and skilled personnel at one central location. JPT P. 662

Process design for offshore oil and gas production in cold ocean environment

AbstractMany considerations influence the design of offshore oil and gas processing facilities such as type of platform, weight and space limitations, environmental conditions, government regulations, drilling support, enhanced recovery, and logistics of supply and market factors. Some of these factors have major impacts on the design and make offshore facilities different from those on land.This paper discusses some typical case scenarios with particular emphasis on processing crude oil in a cold ocean environment such as the Grand Banks off Newfoundland or Beaufort Sea. It describes certain basic requirements for the process design on offshore platforms. Every design is unique for its particular situation.

Design-safety enhancement through the use of hazard and risk analysis

The application of qualitative and quantitative hazards/risk analysis methods is discussed. Two examples of both qualitative and quantitative methods are discussed. The relative advantages of each, as well as relative manpower requirements for their application, are examined. The two qualitative analysis examples are: (1) hazards and operability (HAZOP) analysis, based on the conceptual design analysis of an offshore gas-processing platform, and (2) a qualitative fault-tree analysis based on a design review of a land-based oil-processing facility. The two quantitative analysis examples are: (1) the use of event sequence diagrams for the risk analysis of a batch chemical-operation plant, and (2) an event-tree analysis relative to the consequences of the loss of electric power for the same batch plant. In these examples, design operations and maintenance-safety enhancements that have been implemented are identified. >

Modularization Concepts For The Norman Wells Expansion Project

Abstract Esso Resources Canada Limited is currently completing an oilfield expansion project at Norman Wells, Northwest Territories. Crude oil production will be increased from 475 m3 per day to 4 800 m3 per day. Due to the remote location and harsh climate of the Norman Wells site, it was decided to modularize the Central Processing Facility to the maximum possible extent to achieve a significant cost saving. The 64 modules were built at a modularization site in Edmonton, resulting in higher labour productivity and lower on-site support costs. Virtually all facilities were modularized, including equipment, pipe racks and electrical cable tray racks. Module weights ranged up to 143 tones. Transportation of the modules involved trucking to Hay River, Northwest Territories, and barging to Norman Wells on the Mackenzie River. A novel approach was used to quickly unload, transport and set the modules in place at the site. This paper discusses some of the engineering and execution challenges encountered by the project and the lessons learned in modularization technology. Introduction Esso Resources Canada Limited is currently completing an oilfield expansion project at Norman Wells, Northwest Territories. The town of Norman Wells is located on the Mackenzie River, 156 km south of the Arctic Circle. About 60% of the oilfield lies beneath the Mackenzie River. The remainder is located under the north shore and under two natural islands in the river. Under the expansion scheme, crude oil production will be increased from 475 m3 per day to 4 800 m3 per day. The major facilities constructed for the project are six artificial islands in the Mackenzie River, 164 production and injection wells, a production gathering and injection pipeline system and a central oil and gas processing facility. Interprovincial Pipe Line (NW) Limited is building a new buried pipeline to ship the produced crude oil south from Norman Wells to Zama, Alberta. Because of the project's remote location and the harsh climate at the Norman Wells site, it was determined very early that substantial cost savings could be achieved through modularized construction, particularly for the Central Processing Facility (CPF). By transferring work from the Norman Wells site to a modularization site in Edmonton, construction could be done at a higher productivity and, therefore, cost fewer man-hours. Modularization could also save the costs of subsistence, transportation and the need to work overtime at the Edmonton site. Processing Facilities The Norman Wells CPF is designed to process 4 800 m3 of crude oil and 425 000 standard m3 of gas per day. Gas processing involves supplying lift gas and fuel gas and recovering propane and stabilized condensate. The crude oil and condensate are blended and chilled to −4 °C before entering Interprovincial pipeline for shipment to Zama. The CPF treats 7 000 m3 of water per day from the Mackenzie River for injection into the reservoir. Produced water from the formation is also treated and injected. Three 7.4 MW gas turbine generators supply the electrical power to operate the plant and to supply power to the oilfield and the community of Norman Wells.