rybina_ea_i_dr_angliiskii_iazyk_dlia_magistrov_i_aspirantov

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Conclusions

1.The reaction of Hamaca extra-heavy crude oil in the presence of tetralin, steam, the natural formation, and methane results in a 3 degree increase in API gravity of the upgraded product, a three-fold reduction in its viscosity, and an 8 wt% decrease in asphaltene content.

2.Continuous bench scale plant and composition-thermal simulation showed a good match between experimental and calculated gravity of the upgraded crude and asphaltene content.

4) Строительство и эксплуатация нефтегазопроводов, баз и хранилищ

EU study of Caspian area oil, gas pipelines compares routes, costs

Under auspices of the European Union, two studies of pipeline transportation out of Caspian Sea producing areas have concluded that such systems are technically, economically, and environmentally feasible but depend critically on route selection.

The studies were conducted by ILF Consulting Engineers, Munich. Kvaerner Process Systems AS, Lysaker, Norway; Snamprogetti, Milan;

and Partex – IGE SA, Lisbon, within the frame of the European Union's Tacis INOGATE program. (Tacis = Technical Assistance to the Commonwealth of Independent States; INOGATE = Interstate Oil and Gas Transports to Europe).

Both studies were concerned with the technical, economic, and environmental feasibility of new complementary export routes up to the existing or planned international oil and gas pipeline connections that are suitable for access to the markets of Europe under an expanded EU. The article highlights the main results of these feasibility studies.

Caspian area potential

The Caspian Sea region contains considerable hydrocarbon resources, and a growing number of international companies are developing known Caspian oil and gas reserves or are exploring for additional resources.

One of the main issues facing Caspian-area oil and gas development, however, is the great distances from the producing areas to European markets. This distance implies the construction of long pipelines that must cross several countries before reaching marine terminals or pipeline connections serving prospective European importing countries.

The existing pipeline infrastructure in the region around the Caspian Sea consists largely of pipelines originally designed mainly to supply the internal market of the former Soviet Union (FSU).

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Therefore, export of Caspian oil and gas to Europe requires creation of new complementary transport-transit export systems that could combine onshore and offshore oil and gas pipelines, marine loading and unloading terminals, and associated sea transport by tanker as the primary goal together with the rehabilitation and expansion of the existing transport systems. The first Tacis project focused on the technical, economic, and environmental feasibility of transporting significant oil and gas volumes from Caspian producing countries of Azerbaijan, Kazakhstan, Turkmenistan, and Uzbekistan to European markets through new pipelines crossing the Caspian Sea.

In this context, the potential on and offshore oil and gas production from these countries had to be assessed, the need of new transport facilities analyzed, and on and offshore corridors for the Caspian Sea crossing pipelines identified.

Furthermore, the technical, economic, and environmental feasibility of these new pipelines including their related necessary upstream and downstream facilities had to be studied.

The second Tacis project dealt with the technical, economic, and environmental feasibility of creating new complementary interconnecting export systems or routes (pipelines) from the Caspian oil and gas producing areas to European markets. These systems include a combination of on and offshore pipelines, marine loading terminals, and associated transports by tanker.

In this context, the oil and gas transport and transit capacity of Caspian countries had to be assessed and the need and timing for additional oil and gas pipeline systems defined. These systems include treatment, storage, and other transport facilities required to establish continuous and reliable links between the producing areas and the market.

It was also necessary to evaluate the technical, economic, and environmental feasibility of new pipelines including their necessary upstream and downstream facilities.

Supply, demand analyses; transport scenarios

Analysis determined the current crude oil and natural gas supply and demand situations within, on the one hand, producing Caspian region countries and, on the other, consuming European countries, as well as projections for 20 years.

In addition, the studies defined three different scenarios (high, medium, and low) of hydrocarbon developments in the Caspian region along with transport quantities available for exports to European markets.

This process took into account transport capacities of existing and planned oil pipelines of the Caspian Sea region as well as previously mentioned different scenarios.

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It found only 22 million tonnes/year (tpy) of crude would be available for the trans-Caspian oil pipeline originating from Kazakhstan, Uzbekistan, and Turkmenistan by 2010.

Addition of Azerbaijan's projected or potential crude oil exports to the European market yields an oil transport quantity of 50 million tpy available by 2010 for the pipeline section westward as a continuation of the oil pipeline system crossing the Caspian Sea. The complete possible oil export quantity of Caspian region dedicated for Europe will increase to 100 million tpy by 2020.

Considering the planned Turkmenistan-Iran-Turkey natural gas pipeline as well as the different gas development and production scenarios of the Caspian region, there is enough gas available to launch the trans-Caspian natural gas pipeline to export 14 billion cu m/year now and 47 billion cu m/year by 2010.

Addition of Azerbaijan's projected or potential natural gas exports to European markets indicates the availability of a natural gas transport quantity of 50 billion cu m/year by 2010 for the pipeline section westward as a continuation link of the gas pipeline crossing the Caspian Sea. The total possible gas export quantity of the Caspian region allocated for Europe will increase to 100 billion cu m/year by 2020.

Potential pipelines

The pipeline route for Caspian Sea crude oil mainly from Kazakhstan starts at the Tengiz oil field and runs south to the possible landfall points on the eastern coast of the Caspian Sea.

After crossing the sea, the oil pipeline arrives near Baku at the Azerbaijan's peninsula of Absheron in order to absorb the Azeri crude and to continue further westward as a land pipeline.

From this landing point on the northern coast of Absheron, the pipeline reaches the southern coast of the same peninsula at the oil terminal of Sangachal. This location is an intermediate oil-receiving terminal for Caspian crude flowing along the eastwest corridor via the trans-Caspian oil pipeline.

From here, the oil pipeline route runs westward within the same corridor of the existing Baku-Supsa early-oil pipeline.

The pipeline route for Caspian natural gas mainly from Turkmenistan starts at the Shatlyk gas field in southeastern Turkmenistan and runs north then turns west as a new gas pipeline up to the previously named two possible landfall points.

After crossing the sea, the gas pipeline arrives near Baku in order to absorb Azeri gas and to continue further westward.

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ALTERNATIVE PIPE COUPLING SYSTEM USED IN MIDDLE EAST

Part I

An alternative method of joining segments of line pipe for installation was employed this summer for pipeline installation in Abu Dhabi.

The positive-seal coupling system, supplied by Jetair International Inc., Houston, is a high-strength alternative to welding for joining 2 to 12 in. OD pipe.

Through last April, the company produced 10,405 couplings for the 124km, 10-in. pipeline that is part of the Abu Dhabi Onshore Gas Development project.

These were shipped to the Al-Qahtani Pipe Coating terminal in Saudi Arabia where the line pipe was being coated internally and externally. There, the couplings were installed on one end of each joint of pipe.

Posiseal system

The coupling, developed in 1979 and first patented in 1982, was originally for use with internally coated pipe, eliminating as it does the need for internal girth weld coating repair. The coupling is also suitable for bare pipe.

Pipe wall-thickness schedules of up to 160 and API 5L Grades through X- 60 can be accommodated, says Jetair. Pipeline construction time is significantly reduced in part because the positive seal pipeline connection requires no X-ray.

Minimal pipe-end preparation is required. And there is no ID size restriction to product flow or pigging operations, no loss of pipe length during make up, and no stress fatigue or cracking of pipe ends.

The coupling connection has 100% pressure, stress, and load capability under ANSI/ASME Piping Codes B33, B31.4, B31.8, and under CAN/CSAZ183, Z184 and complies with the requirements of U.S. Department of Transportation 49 CFR Parts 192 and 195.

The patented seal coupling uses a press-on mechanical metal-to-metal interference fit and features a coupling with finely machined internal serrations. The tapered interference fit of the coupling ID is machined smaller than the OD of the line pipe it is designed to join.

This controlled interference fit, in conjunction with the serrations on the ID sur face of the coupling, says the company, produces a connection that exceeds the minimum yield specifications of the pipe itself.

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Part II

Installation

Before the pipe ends are connected, a sealant, normally a specially formulated epoxy, is applied to the OD surface of the pipe ends and the ID surface of the coupling.

With a patented positive-seal field joining unit, the pipe is then hydraulically pressed into the coupling to a premarked insertion depth - one half of the coupling length - producing a connection with a metal-to-metal seal.

The epoxy serves as a lubricant, preventing metal galling during coupling installation, and cures to form a secondary seal around the pipe ends and throughout the ID of the coupling. A shaped seal-ring gasket can also be used between the pipe ends to form a redundant seal in the pipe connection.

With no overlapping of pipe ends, each joint retains its original length. Jetair says that other joining methods, such as the "bell and spicket"

method, can reduce pipe up to 1 ft/connection in insertion depth alone, as well as reducing line pipe ID, with a resulting reduction in flow characteristics.

Those techniques also "cold work" the pipe ends which produces longitudinal stress risers in the "bell" as a result of the swedging operation. Stress risers cause the loss of expensive pipe due to "split ends" and increase the chances of sulfide-stress cracking and corrosion. Because the positive-seal coupling system completely eliminates the need for welding, pipelines can be built with the benefit of internal coating, which protects them from corrosive fluids and enhances product flow.

The internal pipe coating also prevents formation of iron oxides, iron sulfides, and other common bare-pipe contaminants.

The coupling system is used extensively in highly corrosive pipeline applications including CO; injection, water injection, brine-water disposal wells, plus the produced, fluids of oil, saltwater, and natural gas containing H2S and CO2.

Part III

Joining unit; economics

The positive-seal field-joining unit is portable with its own hydraulic power source. It holds in place the pipe end that is to be inserted, then it into the coupling with hydraulic rams and clamping slips.

The pipe slips and coupling backups maintain true alignment during insertion and ensure a strong, lasting connection, says Jetair.

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The joining unit is suspended by a sideboom tractor and easily moves down the pipeline from one coupling insertion to the next. For marine pipeline installation, the unit can be transported on a barge.

Jetair manufactures the joining units in several different models to handle a variety of line pipe.

At present, Jetair manufactures couplings and equipment for pipeline construction through 12-in. nominal pipe size, with plans for future expansion to accommodate pipe sizes through 16-in.

The economics of using the coupling system derive in part from there being no pipe loss experienced with the couplings. Additionally, the pipeline operator is spared costly X-raying of welded connections.

With the joining unit performing the actual line pipe assembly when the positive seal process is used, expensive and unnecessary man-hours are saved.

With coupling insertion taking only 60 sec to complete, pipe lay rates are much faster than with welded connections. The heavier the pipe wall, the more economical the positive-seal couplings, says Jetair, compared with welded pipe, coated or uncoated.

PRODUCTS PIPELINE REHABILITATED WHILE ON STREAM

Part I

Rehabilitation of a 186-mile petroleum products pipeline in southern Africa employed sleeve welding, reinstatement of external coatings, and upgrading of the cathodic-protection system.

The pipeline had an unusual history in which the political environment of the region forced its shutdown for 17 years. This shutdown played a major role in its deterioration.

The pipeline, which exhibited extensive internal and external corrosion, was a crucial supply route for imported refined products. So important was the line that during the entire repair project, the line could not be shutdown.

This technical difficulty was compounded by various practical difficulties as well.

Shutdown

The 300-km, 10.75 in OD x 0.250-in. W.T. pipeline was fabricated from API 5L X-46 line pipe. It was originally installed in 1964 and commissioned in 1965 to transport crude oil to a (then) new refinery.

Its main facilities are two pump stations and one terminal.

The shutdown of the pipeline lasted from 1965 to 1982. During shutdown, maintenance of the cathodic-protection (CP) system was impossible. This caused most of the external corrosion.

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Crude oil was also shut in during this period. In 1981, this crude was evacuated from the line and the line converted to multi-products because the refinery downstream had fallen into disrepair.

Refurbishment began in 1981 with replacement of 40 km of the most heavily corroded pipe, and another 40 km lifted, cleaned, and rewrapped. The line was recommissioned and operations begun in 1982.

In 1983, a program of wrapping repair and replacement followed a closeinterval potential survey.

In 1987, to improve the operating condition of the pipeline, the pipeline operating company initiated further investigations of the status of the pipeline. This effort led to the work under discussion here.

Part II

Coatings, CP history

The original wrapping system was a fiber glass reinforced coal-tar enamel; the impressed current CP used 14 transformer rectifier sets with horizontal groundbeds consisting of silicon iron anodes in coke breeze backfill.

As part of the 1981 refurbishment, the 40 km of replacement pipe was coated with factory-applied extruded epoxy/polyethylene coated pipe.

The lifted length was stripped and rewrapped with a polyethylene/butyl laminate tape. Further localized wrapping repairs were carried out with Denso petrolatum innerwrap with an adhesive polyethylene outerwear.

At the same time, the CP system was re-designed and new groundbeds and transformer rectifiers (TR) installed. Some of the old TR sites were abandoned, and additional units installed where insufficient spread was obtained.

New power supplies and standby diesel alternators were also installed. There was no assessment of internal corrosion during this early work.

Once the pipeline was operational, an overline close-interval polarized potential survey was conducted to determine the effectiveness of the CP system and locate any areas, which still required wrapping repair.

One of the most significant results of the survey was the accurate status record of the first 13 km of the pipeline. This was one of the most corrosive areas of the route, being rice fields, and also had the greatest potential for consequential damage should a leak occur.

Consultants had proposed that this section of the line be replaced, but the closeinterval survey showed that only 1 km of pipe required new rapping.

Excavation revealed this section had no corrosion, despite extensive loss of wrapping, because it was adjacent a CP station. The result was a major cost savings.

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A priority-based repair program was instituted to carry out the necessary repairs to the wrapping system. These repairs were effected with the (then) relatively new polyethylene-backed rubberized bitumen tapes.

A local product was used because it was found that the U.K.-sourced tapes tended to flow at high ambient temperatures. This tendency presented a storage rather than a service problem.

One of the difficult aspects of this phase of the program was the existence of significant lengths of pipeline on which the CP potentials were inadequate, but there were no suitable groundbed sites and power supplies were few and far between.

These areas tended to have relatively high resistivity with low resistivity hotspots to the extent that made achieving protection by increasing the output of the TRs impossible.

Part III

Pipeline inspection

Pipeline intelligent pigging was carried out between September 1989 and January 1990 with a British Gas On-Line Inspection vehicle.

Six runs were carried out, consisting of one pass with a multigauge vehicle and five with the inspection vehicle. The report confirmed that the pipeline had suffered extensive internal and external corrosion.

The internal corrosion was predominantly located in the 4-8 o'clock quadrant and, in some sections of the pipeline, appeared to extend throughout the bottom section. The external corrosion was more randomly distributed in all quadrants and along the entire length of the pipeline.

An automatic computerized process was used to grade the metal-loss features according to their estimated depths. This information was displayed as a list of sequential girth welds, with metal-loss indications identified by their distances from the upstream girth weld and by their orientations viewed in the direction of flow.

A code system was utilized to identify the metal loss as follows: no star = 0-30% metal loss; * = 30-50% metal loss; ** = 50-70%; and *** = 70% and higher.

Distribution of the metal-loss indications along the pipeline was shown on histograms based on the number of features per 100 m of line length.

No original chainage records were available and the line has an erratic path in places. This resulted in some practical problems in relating the location data from the intelligent-pig survey to the pipeline as laid.

The line had been constructed with double random lengths of pipe, and the variable lengths of these were used to advantage to assist with locating

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defects. Where repairable events were detected and not readily found, the pipeline was excavated for at least three pipe joints.

These were measured and compared with the circumferential weld indications on the pig data log and used to give a precise local fit to the repairable event. It was also found to be necessary to confirm reported events with ultrasonics.

Re-evaluation of the intelligent pig data was requested from the pig operator when the reported "serious events" could not be located. In several such cases this more detailed analysis resulted in the significance of the defect being reduced.

Part IV

Hydrostatic testing

Obtaining sufficient water for hydrotesting is rarely a problem in developed countries and the chemical composition of test water is only of concern if high chloride levels would cause corrosion in stainless steels.

In developing countries, on the other hand, the availability of sufficient clean water for hydrotesting can be a significant obstacle. Obtaining sufficient water to fill the pipeline for testing was overcome by damming a local stream for several weeks. This practice dictated the lengths of line that could be tested. The open end had to be relatively adjacent to the water supply.

There were concerns about the general water quality and that the water would hold large amounts of mud.

Samples of the water were sent for analysis, which showed that it contained sufficiently high levels of coli-form bacteria to "endanger both site personnel and the pipe itself.

Contact with this type of water can lead to dysentery, typhoid, or salmonella.

This concentration of coli-form organisms is also associated with high levels of sulfate-reducing bacteria (SRBs), which could cause internal corrosion of the pipeline. The mud in the local river water proposed for hydrostatic testing would settle down on the lower quadrant of the pipe, thereby increasing the extent of localized corrosion damage, particularly in the presence of SRBs.

In a western-style operation, it would be recommended that the source water should be filtered and treated with both an oxygen scavenger and an organic biocide when used for hydrotesting. This approach was unpractical for this project.

Considerable care was taken in evacuating the hydro-test water from the pipeline after testing to avoid the corrosion risks stated above. Several passes

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were conducted with a variety of pigs to ensure that the line was thoroughly cleaned and dried.

Are We Ready To Construct Submarine Pipelines in the Arctic?

Submarine pipelines in Arctic seas have been under consideration for more than 25 years but few have been built. Technical difficulties include ice gouging and subgouge deformation, strudel scour, marine permafrost, and leak detection and repair. The objective of the full-length paper is to review the state of knowledge and to assess the readiness of the pipeline industry for Arctic pipeline development.

Introduction

Twenty-five years ago, Arctic offshore hydrocarbon resources seemed on the verge of rapid and energetic development, but cost and technical uncertainty made the economics questionable. Today, some Arctic projects appear economically and technically feasible and are receiving renewed interest in both the North American and Russian Arctic although there are still technical questions and environmental opposition. All indications are that the industry will begin with the less ambitious and less difficult projects and apply the lessons learned to the more difficult projects.

Ice Gaoging

Large masses of ice are pushed by ice sheets and pack ice driven by wind and currents. In the western North American Arctic and in the Arctic islands there are no true icebergs but many multiyear ridges and occasional ice islands. True icebergs exist in the eastern Arctic.

When ice masses run aground they continue to move and can cut gouges more than 50 m wide and 5 m deep into the seabed. The most intense gouging occurs in water 20 to 30 m deep. Research has confirmed that ice gouging is a contemporary process (gouges seen today are not relics left over from different climatic conditions or sea levels). The force required to cut a deep gouge is of the order of 100 MN. Gouge profile interpretation is complicated by the fact that a profile is a dynamically changing picture influenced by gouge infill produced by repeated gouging and by normal seabed-sediment transport caused by waves and currents.

Burying the pipeline below gouge depth is not sufficient for pipeline protection because intense deformation occurs beneath a gouge and the pipeline can be damaged by being dragged with the seabed soil below a gouging ice mass.