Enterprise Energy Ireland Ltd Corrib Offshore EIS RSK/H/P/P8069/03/04/01rev01 4-1 4. ALTERNATIVES .......................................................................................................4-1 4.1 Need for the Scheme .................................................................................4-1 4.1.1 Energy Sources in Ireland............................................................... 4-1 4.1.2 Need for the Field Facilities, Pipelines and Umbilical.................. 4-2 4.2 Examination of Alternative Locations .......................................................4-4 4.2.1 Corrib Field ...................................................................................... 4-4 4.2.2 Terminal and Landfall..................................................................... 4-4 4.2.3 Offshore Pipeline Route ................................................................. 4-8 4.2.4 Discharge Pipeline.......................................................................... 4-9 4.2.5 Sruwaddacon Crossings .............................................................. 4-10 4.3 Examination of Alternative Design..........................................................4-10 4.3.1 Corrib Field Facilities ..................................................................... 4-10 4.3.2 Facilities, Pipelines and Systems .................................................. 4-10 4.4 Examination of Alternative Processes ....................................................4-12 4.4.1 Options for Drilling......................................................................... 4-13 4.4.2 Options for Hydraulic Valve Control ........................................... 4-15 4.4.3 Options for Hydrate Inhibitor ....................................................... 4-16 4.4.4 Options for Scale Prevention....................................................... 4-17 4.4.5 Options for Corrosion Protection................................................. 4-20 4.4.6 Options for Treatment of Produced Water ................................ 4-20 4.5 Options for Construction/Installation ......................................................4-20 4.5.1 Offshore Installation of the Gas Pipeline .................................... 4-20 4.5.2 Landfall .......................................................................................... 4-21 4.5.3 Sruwaddacon Crossings .............................................................. 4-21 Table 4.1: Comparison of Hydrate Inhibitors ............................................................ 4-18 Figure 4.1: Potential landfall areas ............................................................................... 4-6
Table 4.1: Comparison of Hydrate Inhibitors ............................................................4-18
Figure 4.1: Potential landfall areas ...............................................................................4-6
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4. ALTERNATIVES
4.1 Need for the Scheme
With gas consumption increasing annually and predicted to rise sharply in the future, demand for energy has outstripped Ireland’s domestic production and infrastructure capacity. Consequently, Ireland has required additional imports of gas from abroad since the mid 1990’s.
Bord Gáis Éireann (BGE) commissioned consultants to evaluate the required strategic investment in gas transmission infrastructure throughout Ireland until the year 2025. As a result, the Government has recently approved further pipeline connections between Scotland and Dublin, and a significant increase in the onshore transmission system from Dublin to Galway and Limerick, which completes a ring main with the existing gas network between Dublin-Cork-Limerick.
However, the depletion of existing resources at the Kinsale Head gas field means that indigenous gas will form a decreasing proportion of the gas used in the Irish market. Further, the UK, from where Ireland imports around 70% of its gas, is itself predicted to become a net importer of gas by 2004. Ireland will therefore become largely dependent for its gas supply on a country that is itself a net importer of gas. The development of Corrib will provide indigenous security of supply and stimulate expansion of the onshore transmission system to the north-west of the country, which in turn will result in increased possibilities for economic growth in this region of Ireland.
At present, Ireland is experiencing high economic growth accompanied by expectations for a higher standard of living. These factors, amongst others, drive the demand for greater use of power and energy. Gas is also predicted to become a greater provider of energy in Ireland due to its positive environmental profile compared with traditional sources and the Government’s Kyoto Protocol commitments. This, combined with the current liberalisation of the energy markets and the increase in number of combined cycle gas turbine (CCGT) power stations will lead to increased gas consumption in Ireland. Infrastructure investments, of which the development of the Corrib Field is a significant part, will cater for the predicted increased national demand for gas, contributing to the long term economic well-being of Ireland.
4.1.1 Energy Sources in Ireland
Ireland currently consumes coal, oil, gas, wind, peat and hydroelectric power as sources of energy. As the demand for energy increases, it is expected that gas will assume increasing importance because of the efficiency of energy use in CCGT generators and the resulting relatively benign environmental impact of the emissions.
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Substitution of other fossil fuels by natural gas in power generation has the potential to assist in achieving Ireland’s targets for reduction of greenhouse gas emissions under the Kyoto Protocol.
4.1.2 Need for the Field Facilities, Pipelines and Umbilical
The area in which the Corrib Field is situated is characterised by a harsh marine environment (being directly exposed to the open Atlantic swell), a lack of existing hydrocarbon production infrastructure and the presence of active fisheries interests.
In order to extract the gas from the hydrocarbon-bearing structure (Sherwood Sandstone reservoir) a number of wells are required. The gas migrates into the well bores under its own pressure and moves to the wellhead. The infrastructure which is to be installed between the wells and the BGE system needs to be capable of controlling the flow rate from the wells, transporting the gas to shore and drying the gas to the BGE specifications. The gas also needs to enter the BGE system at the correct pressure.
There are two main options to achieve this:
• an offshore gas processing facility situated on a platform, with a pipeline to shore with some gas handling capacity (reception facility) onshore; and
• a subsea gathering system to collect and transport the gas to shore for processing in an onshore terminal.
A reception facility (in this case the Terminal) is required at a position close to the landfall, whether or not there is offshore gas processing.
Apart from the need to remove water from the gas (a process which involves pressure reduction), there is the need to repressurise the gas and add odorant.
Conceptual assessments concluded that due to the water depth, the harsh environment at the field location and to the need to identify an economically viable method of development, the most practical, beneficial and best technical solution would be carry out the gas conditioning onshore. The reasons for this are discussed below.
4.1.2.1 Development Concept Alternatives Considered
A number of development concepts were identified. Screening exercises were conducted to select and define the preferred development strategy. The principal alternative development concepts considered were:
• construction and installation of a deepwater platform standing on the seabed, with processing, drilling and accommodation facilities;
• construction and installation of a “shallow” water (<100 m depth) fixed steel platform located between the Corrib Field and the shore with minimum facilities, together with the installation of associated subsea
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infrastructure (feeding gas from Corrib);
• construction and installation of various types of floating production vessel; and
• construction and installation of a subsea gas gathering system, tied back to an onshore gas reception Terminal.
The first three options would require offshore processing and accommodation facilities. All would require a gas pipeline to transport the gas to shore and all would require an onshore reception facility.
4.1.2.2 Reasons for Elimination of Alternative Concepts
The only feasible development scenario is a subsea system tied back to a processing Terminal onshore.
The reasons why this concept was selected are as follows:
• the relatively dry nature of the Corrib gas and the high reservoir productivity permits the practical adoption of subsea production technology;
• all the options involving an offshore manned facility (whether fixed or floating) have increased adverse safety implications, particularly with respect to offshore transfer of personnel, and result in high operational expenditure;
• the great water depth and hostile nature of the environment at Corrib do not favour the use of a fixed steel jacket (platform) or guyed tower;
• floating production concepts are not well suited to high reliability gas exports and to extended field life in the prevailing harsh environment; and
• the floating and fixed platform options considered (with the requirement for gas transportation and onshore gas reception infrastructure) have high capital costs which, in combination with the volume and predicted gas price for the Corrib gas, rendered their adoption uneconomic.
4.1.2.3 Development Concept Selected
The preferred feasible development scenario, which has been selected for the Corrib Field, is a long-range subsea tie-back to a processing Terminal onshore. It is expected that eight subsea wells will be required to economically and effectively abstract gas from the field. However, the number of wells could be as low as five (already drilled), or as high as nine. The actual number required will not be known until the Field has been in production for several years.
The offshore pipeline will carry gas from the Field to the landfall at Dooncarton, Co. Mayo, and from there to the gas reception Terminal. The Terminal will be located near Bellanaboy Bridge in County Mayo. Gas will be exported from the Terminal via a Bord Gáis Éireann owned and operated pipeline to tie-in to the Bord Gáis Éireann ring main at Craughwell, County Galway.
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4.2 Examination of Alternative Locations
Two main locations were considered; the Corrib Field, and the location of the gas reception terminal.
There are no options to the location of the Corrib Field, as it is determined by the location of the gas reservoir. The process by which the location of the Terminal was determined is described below.
4.2.1 Corrib Field
The Corrib Field is located in the Atlantic Ocean, some 65 km off the west coast of Ireland (as shown in Figure 1.1).
4.2.2 Terminal and Landfall
The existing natural gas transmission pipelines are in the east and south of Ireland. Therefore, connecting the Corrib Development to the existing network would require a long pipeline connection. The Terminal is an integral part of a gas transmission system from the Field to the market. Selecting the Terminal location was a function of the characteristics and behaviour of the untreated gas from the Corrib Field and onshore siting considerations.
The characteristics and behaviour of the untreated gas flowing from the Corrib Field to the Terminal present a number of technical constraints. Due to the pressure, temperature changes and the chemical composition of the gas, ice-like crystals known as “hydrates” can form in the pipeline. To counter this possibility, hydrate inhibitor is injected into the well fluids in the Field. However, the presence of water and hydrate inhibitor in the pipeline causes slugging. The distance between the wells and the Terminal influences the operability of the system. The Terminal has been located as near as possible to the landfall, in order to keep the distance between the wells and the Terminal to a practical minimum.
The environmental impact of the Corrib Project as a whole was considered. The process of defining the most suitable locations for the Terminal and landfall was essentially an iterative one. Consultants were commissioned in 1998 to review the seabed and coastal morphology of the West Coast of Ireland from the mouth of the Shannon to Sligo in order to determine suitable locations to bring a pipeline ashore. The review was undertaken using aerial photography, geological information, mapping and site visits. The review concluded that, along the West Coast of Ireland, there are extensive areas of seabed where rock outcrops exist. This severely limited the number of locations suitable for bringing a pipe ashore. The review identified four main areas where a suitable landfall was most likely to be found.
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They were as follows:
• Killala Bay area, in counties Mayo and Sligo;
• the eastern side of Broadhaven Bay and Blacksod Bay in Co. Mayo;
• the Emlagh point area, to the west of Westport in Co. Mayo; and
• Liscannor Bay and Doughmore Bay in the central point of Co. Clare.
The above locations (see Figure 4.1) were then subjected to a more detailed appraisal in terms of:
• environmental constraints;
• offshore pipeline routing;
• technical feasibility and costs;
• pipeline shore approach and landfall construction issues;
• possible onshore terminal locations; and
• onshore pipeline routing and construction considerations.
This appraisal refined the previous information and led to a more detailed feasibility study for four areas. These locations were:
• north or south of the Sruwaddacon inlet, in Broadhaven Bay, Co. Mayo, with the reception terminal nearby;
• Bunatrahir Bay, Co. Mayo, with the reception terminal within 0.5 km of the landfall;
• Ross Point on the south side of Killala Bay in Co. Mayo, with two possible reception terminal sites, one at the landfall and the other some distance inland at the former Asahi plant; and
• between Lenadoon Point and Rathlee Head, on the east side of Killala Bay, Co. Sligo, with the reception terminal at the landfall.
All of the options were reviewed and the best terminal site identified for each landfall. The main selection criteria were:
• to minimise impact to environmentally sensitive areas;
• minimise shore to terminal distance; and
• to keep visual impact to a minimum.
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Figure 4.1: Potential landfall areas
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Brief conclusions were as follows:
• Rathlee – primary constraint identified was the visual impact of the Terminal. All locations are highly visible and would have been difficult to screen.
• Killala – several landfall locations were considered around the bay. The suitable landfall location was a designated Special Area of Conservation (SAC) and a Natural Heritage Area. The other was a recreational beach area. The areas to the west of the bay were the best landfall locations, but are designated as being of Special Scenic Importance. No suitable Terminal location could be identified within a suitable distance.
• the option of locating the Terminal at the former Asahi site was considered. This would entail a subsea pipeline and umbilical system length of approximately 145 km. An umbilical of such a length would be the longest ever manufactured, and would have had significant technical and manufacturing risks associated with it. Hydraulic modelling also predicted substantial slugging in the pipeline, especially during flow variations. The option of building a control station for the umbilical at a separate location closer to the field and laying the umbilical from there, was also considered but discounted on the basis of practicality, safety, security and cost. Moreover, the Terminal would require additional power for gas compression and inhibitor pumping. This would increase the size of the facilities and associated environmental emissions onshore and because of the long distances involved, result in excessive pressure loss in the subsea pipeline and in the hydrate inhibitor line(s). For the above reasons this alternative was discounted due to technical risk, lack of operational flexibility and cost.
• Bunatrahir-the beach area is designated as an area of special recreational importance. Also, it is possible that extensive sandstone bedrock in the area could cause problems for landfall construction. The nearby beach at Portnahally was also considered. One of the main disadvantages was the visibility of potential Terminal sites. The land is very flat and exposed and the sites were particularly visible from the R314 into Ballycastle.
• Broadhaven Bay – a location was selected which is within a farmed forestry plantation which provided natural screening for the Terminal. Although the bay is a candidate SAC, the Terminal development is not in an area covered by the proposed SAC, however, the selection of this site was the subject of discussions with Dúchas. Locating the landfall and Terminal in the Broadhaven area also offered a practical option, with lower technical risk during construction and operation. The ground conditions of the foreshore and approach are gently sloping and predominantly sand and are suitable for landfall construction. The sediments in the nearshore approaches are in a natural state of flux, hence disturbance to the benthic habitats from construction would not be significant, or more than of short duration. A detailed analysis of the pipeline route options considered between the landfall and the Terminal is included in Section 19.
An alternative Terminal location in the Broadhaven Bay area was also considered. The site was located south-west of Pollatomish at the bottom of
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the hill inland from Brandy Point. Whilst the location cannot be seen from the south-west, it is impossible to screen it effectively from the road or from some residential properties. It would be completely open to the seaward from the bay. Given the scenic nature of the area, and the conservation status of the bay, the currently proposed Coillte-owned site at Bellanaboy Bridge was considered much less intrusive.
On the basis of the above, it is proposed to construct the Terminal near Bellanaboy Bridge and to construct an offshore pipeline which will come ashore at Dooncarton, near the Sruwaddacon inlet, in Broadhaven Bay.
4.2.3 Offshore Pipeline Route
Once the position of the Terminal had been established, the exact route of the line needed to be considered.
The fixed points at the beginning of the detailed surveys of the route were the Corrib Field and the proposed Terminal. During 2000 a survey vessel was contracted by Enterprise to carry out detailed seabed survey work to determine the best route for the pipeline. The aspects which were considered in determining the route, both in survey and desk study terms included:
• length of route;
• seabed sediments;
• presence of protected areas/species;
• presence of specific fishing/spawning areas; and
• presence of wrecks.
The survey vessel spent a considerable time at sea, in order to establish the seabed conditions. A suitable route between the Corrib Field and a landfall point at Dooncarton was identified.
The length of the route will influence the cost of the pipeline. It is also recognised that the shorter the pipeline route is, the less disruption there will be to the seabed sediments. Soft sediments are the easiest type into which a pipeline can be installed, and the chosen route traverses soft sediments for the majority of its length.
The desk study and consultations did not identify any areas of particularly high fishing or spawning value (though it is known that fishing occurs throughout much of the length of the proposed route). The construction of the pipeline is not anticipated to affect the integrity of the Broadhaven Bay SAC. There are no records of protected species from the pipeline route, nor did the benthic survey identify any particularly unusual species.
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There are records of many ship wrecks in Broadhaven Bay. In order to ensure that no wrecks would be disturbed, a Dúchas approved study was undertaken (see Section 14). No wrecks were identified along the proposed route.
The proposed route of the pipeline is shown in Figure 1.2.
4.2.4 Discharge Pipeline
The Terminal will generate waste water which consists of treated rainwater and water removed from the gas stream (water of condensation and formation water). Water treatment is discussed in detail in Section 9 and in further detail in the Terminal EIS. Options for the disposal of the water have been considered and are presented below:
• onshore injection;
• local drainage;
• coastal discharge, no mixing;
• estuarine discharge, no mixing;
• coastal discharge, limited heavy metal removal;
• water treatment and coastal discharge, mixing;
• estuarine, mixing; and
• re-injection into the Corrib reservoir.
The onshore injection and local drainage options were ruled out due to the possible salty nature of the waste water.
Local drainage discharge to Sruwaddacon Bay was ruled out due to the enclosed nature of the south-eastern end of the Bay, which would reduce the potential for mixing and dispersion.
In order to re-inject water into the reservoir, it would need to arrive at an equal or greater pressure than that existing in the formation. This would require much larger onshore facilities for pumping, creating associated environmental emissions onshore. The laying of a second pipeline back to the field to re-inject the produced water into the reservoir would also have required a deeper trench in the seabed.
The chosen disposal option is water treatment, to environmental quality standard levels and coastal mixing. Discharge and dispersion modelling studies have been carried out and are discussed further in Section 9.
Four alternative locations were studied. These were the locations where the proposed gas pipeline route crosses the 10, 20, 30 and 40 m bathymetric contours. The modelling results indicated that the lowest impact on Broadhaven Bay could be achieved by using the 40 m location. Any further extension of the outfall offshore would achieve no significant improvement in impact mitigation. This is discussed in full in the modelling report Appendix 9.1.
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4.2.5 Sruwaddacon Crossings
The selection of the crossing locations is discussed in detail in Section 19.
4.3 Examination of Alternative Design
The purpose of this section is to present the options considered and the selection process for the materials to be used in fabrication, construction, installation and operation of the Corrib Field development facilities.
4.3.1 Corrib Field Facilities
The proposed layout of the subsea equipment (a ‘central’ manifold gathering gas from the wells) is constrained by several factors including:
1. The wish to re-use as production wells the five appraisal wells already drilled in the Corrib Field. This reduces the environmental impact by reducing the need for additional wells. It also reduces drilling costs.
Two of the existing wells (18/20-2z and 18/20-4) have been drilled from the same surface location and it is proposed that the manifold is located next to these wells. Appraisal wells 18/20-3, 18/25-1 and 18/25-3 are located some distance from the proposed manifold location, therefore they will be tied back to the manifold using infield flowlines laid on the seabed.
The precise routing of the infield flowlines to tie back wells 18/25-1 and 18/25-3 is still to be finalised. It is likely that one flowline will be connected to the other and that both wells will then be tied back to the manifold via a single flowline.
2. The need to retain sufficient flexibility in the number and location of future wells to ensure gas from the Field is drained economically and effectively.
The subsea manifold facility is designed such that eight wells can be tied back to it and additional wells required can be added in a ‘daisy chain’ style if they are required. It is intended that the three future production wells will be drilled from a surface location near to the manifold, thus minimising the amount of infield flowlines to be installed on the seabed. Likewise, if additional wells are required, there will be a preference to drill from a location near the manifold. Additional wells, if required, would be subject to prior approval by DOMNR.
4.3.2 Facilities, Pipelines and Systems
The project description (Section 2) provides information on the equipment and systems which have been selected for use in the Corrib development. This section provides information on the alternatives that were considered before the final choices were made.
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4.3.2.1 Materials Selection
The fluids which are exported from the Corrib Field to the Terminal are corrosive in nature. The main corrosive agent in the Corrib fluids is dissolved carbon dioxide (CO2), which forms an acidic solution with water. Although CO2 levels are low, the pipework needs to be protected from corrosion. This can be achieved by:
• corrosion resistant pipe material;
• coating of the inside pipewall to prevent corrosive fluid from coming into contact with the pipe material; and
• adding chemicals which prevent corrosion from occurring.
Inherently corrosion resistant alloys (CRA) are available for subsea pipework. However it is more time consuming and difficult to achieve a perfect weld with these materials than with carbon steel. CRA is therefore an alternative for short lengths, and where structures can be fabricated onshore, but not over the whole pipeline route.
Carbon steel with the use of a corrosion inhibitor is therefore the selected option. The corrosion inhibitor will be injected into the manifold with the methanol (see Section 3).
4.3.2.2 Pipeline Mechanical Design
The gas pipeline size has been selected to be 20" in diameter. The 20" diameter was chosen over smaller diameter and twin pipelines (14", 16" and 18"), despite its greater cost. This was done for several reasons:
• it improves pipeline system operability (including turndown and peak flow capacity);
• it increases the available drawdown and hence allows accelerated production, as the pressure drop for a given flowrate is reduced in the 20" line compared to the smaller diameter lines; and
• it will allow daily production rate changes to largely be achieved using onshore control valves, rather than individual well choke valves, thus increasing the reliability of the subsea system.
No tie-ins or tees are currently planned in the offshore pipeline.
The pipeline design pressure will be set at, or close to, the maximum wellhead shut in pressure of 345 barg, while maximum normal system operating pressures will be in the region of 150 barg. Initial material selection studies indicate that the pipe will be fabricated in API 5L grade X-70 carbon steel with a pipe wall thickness of 28.2 mm. However, this may be revised during the detail design phase. This design pressure will also apply to the short (8 km) onshore section of pipeline from the landfall to the terminal. Detailed risk assessment will be undertaken throughout the design of the facilities to ensure that pipeline risk is reduced, as far as
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reasonably practicable. The pipeline will be designed and constructed in accordance with all appropriate industry codes.
To provide protection from external corrosion, the pipe will be coated and provided with a cathodic protection system using sacrificial anodes (see Section 4.4.5.2), as a back-up, in case of coating breakdown or damage. Internal corrosion protection will be provided in the form of a corrosion inhibitor, which is mixed with the methanol and constantly injected into the flowing pipeline system to form a protective barrier on the internal wall of the pipe.
Periodic internal inspection by “intelligent PIG” run from a temporary subsea launcher will enable the integrity of the pipeline system to be verified. No requirement for regular operational pigging (e.g. liquid removal runs) is envisaged.
The option of using dual pipelines was also examined. An initial analysis indicated that two 14” OD pipelines would most effectively meet the hydraulic requirements. The main benefit of the dual pipelines over a single pipeline would be to allow ‘round trip pigging’. If there are two pipelines, a pipeline integrity gauge (PIG) could be sent from the Terminal to the Field in one of the lines, and return in the other. This would eliminate the need for a subsea pipe launcher. Disadvantages, such as increased trench size and pipe laying time, which would also potentially increase environmental impacts, were judged to be sufficient to rule out the dual pipeline option.
4.3.2.3 Umbilical
Several options for the umbilical were considered, including installation of more than one line, although this would involve the electro-hydraulic and chemical supply lines being separated. It was considered that the installation of more than one umbilical line would be likely to create more disturbance to the seabed than installation of a single line. Alternative materials for the internal core construction were also considered, the options being a type of thermoplastic or steel. Steel tubes were selected, as there is the potential for low level permeation of methanol through the wall of thermoplastic hoses.
In considering the optimal location for a landfall, the operation of the umbilical was also considered. For some of the more easterly landfall locations further from the Corrib Field (see Section 4.2.2), it could have been necessary to terminate the umbilical closer to the Field. However, the shorter distance between Broadhaven and Corrib allows the use of a single site to integrate the gas reception facilities and the Field control system.
4.4 Examination of Alternative Processes
Alternative gas processing technologies are discussed in the Terminal EIS.
Alternatives to the chemicals proposed for the subsea system are limited because of the Terminal processes. Where there are options for the subsea processes, they are presented in the following sections.
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4.4.1 Options for Drilling
The only way to exploit the gas in the Corrib Field is to drill wells into the reservoir from above. The exact seabed location of the wells can be manipulated to a degree, however, to optimise reservoir production there are preferred locations in which to drill into the reservoir. There are two options for drilling into these locations, either vertically drilled wells or directionally drilled (deviated) wells. The technology exists to drill all wells from one drilling location, however, the average length of the wells increases with associated increases in the discharges from drilling. The advantage of having all wells drilled from a single seabed position is that there is a reduction in the amount of subsea facilities which need to be installed to direct the gas once it has reached the top of the wells (i.e. infield flowlines).
Environmentally, the options for vertical and deviated wells involve trade-offs between the quantity of materials and wastes (e.g. mud chemicals and cuttings) and the extent of disturbance to the seabed (from drilling, mooring, subsea installations etc.). The design of the Corrib Field utilises a combination of vertical and deviated wells to a) ensure existing appraisal wells are re-used as production wells, thus minimising the number of new production wells that are required and b) minimise the requirement for infield pipelines while reducing as far as possible the length and complexity of the wells.
Drilling in water depths greater than about 100 m precludes the use of a drilling rig with legs extending to the seabed. The remaining alternatives are semi-submersible mobile offshore drilling units (MODUs) and drill ships. MODUs based on twin submerged pontoons are sufficiently stable when ballasted to allow stands of drill pipe to be racked upright in the derrick. This allows the MODU to rapidly disconnect from the well in stormy weather. Conventional drill ships tend to be less stable, and require longer warning times for adverse weather conditions to enable them to disconnect from the well.
The seabed anchoring system used by a MODU and drill ship are similar. There would be little difference in the disturbance they cause to the seabed when anchoring. Other aspects of drilling from either type of vessel are similar.
The water depth in the Corrib Field dictates that a MODU is the preferred and most economic option.
The wells that have been drilled in the Corrib Field to date allow comparison of conventional five section drilling and casing plans, and ‘slim hole’ well plans with four sections. A feature of the ‘slim hole’ well programme is that the marine riser is installed on the 13.375” casing, rather than on the 20” casing of a conventional well. The slim hole option generates lower volumes of cuttings. It also requires a smaller volume of drilling mud, which reduces the usage of associated chemicals. The slim-hole plan will be used for all future Corrib wells.
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4.4.1.1 Options for Drilling Mud and Chemicals
Drilling operations require the use of a drilling fluid with appropriate shear thinning characteristics used for transport of cuttings, cooling and for hole stability.
In general terms, water-based drilling muds (WBM) are used to drill through rock formations which do not react with the base fluid. When drilling through ‘reactive shales’, such as certain mudstones and claystones, to avoid reactions between the mud and the formation, an organic based mud is required (generally termed oil-based mud (OBM), or synthetic based mud (SBM)). The following paragraphs are written with the above constraints in mind. There is a technical requirement to use organic based muds in the lower hole sections, where reactive shales are encountered.
In the selection of drilling chemicals, Enterprise (and its drilling contractor) have considered the toxicity and volumes of the available materials. Currently, the most complete listing of chemicals used in offshore drilling and production operations is the Oslo and Paris Convention’s (OSPAR’s) Harmonised Offshore Control and Notification Format (HOCNF), established by OSPARCOM Decision 96/3. This decision set out a regime for the environmental testing of toxicity, bio-degradation and potential bio-availability of chemicals. On the basis of this, a UK scheme has been developed which categorises chemicals in environmental grades, ranging from A-E, with E being most environmentally benign. A category Z applies to invert emulsion drilling fluid (OBM or SBM) system components, which can be used, if totally contained, and may not be discharged. Appendix 4.1 provides an explanation of the HOCNF system.
OSPAR’s Decision 2000/2 will replace the HOCNF test grades with environmental risk quotients under a ‘Harmonised Mandatory Control System for the Use and Reduction of the Discharge of Offshore Chemicals’ (HMCS). This was scheduled for introduction by January 2001, and is currently being phased in. As a pre-screening stage, HCMS will consider whether the chemicals are on the PLONOR list of chemicals (pose little or no risk to the environment). HCMS also takes into account expert judgement on sensitive areas, and makes use of Chemical Hazard and Risk Management (CHARM) modelling, to ensure the least damaging chemicals are used. At the time of writing, no listing of risk quotients is in the public domain to match the previous HOCNF listings. The Petroleum Affairs Division (PAD) of the Department of the Marine and Natural Resources has agreed to accept the reference to the UK developed HOCNF classifications for this EIS.
Enterprise’s selection of drilling chemicals has been influenced by the HOCNF and PLONOR classifications, and by regulations relating to discharges. For water-based drilling fluids the associated chemicals are mostly class E or are on the PLONOR list. Appendix 2.1 provides a listing of the chemicals used to date for drilling in the Corrib Field.
The decision to use an invert emulsion fluid for the 12.25” and 8.5” sections has meant taking account of changing regulations, firstly regarding the
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selection of the organic base fluid, and secondly regarding the discharge or total containment of invert emulsion fluids. For the wells drilled between 1996 and 2000, the emphasis was on striving to reduce the amount discharged to the sea with the cuttings. Consequently, an organic base fluid of minimum toxicity was selected. Regulations now allow no marine discharges of organic base fluids and cuttings associated with them. Any cuttings from the sections drilled with the organic base fluid will now be returned to shore for treatment/disposal.
4.4.1.2 Options for Completion Chemicals
The use of chemicals during drilling is regulated by DOMNR, and prior specific approval is required for each well operation.
Completion operations require the use of a variety of chemicals. Operations range from well clean-out, insertion of completion brine, and hydraulic fracturing, to well testing.
The objective for well clean-out is to change over the well fluids from drilling fluids to completion brine. The typical chemicals used for this operation include detergent, flocculent and solvent, to ensure that all drilling fluids are effectively removed from the well.
The completion brine is designed to provide a pressure barrier to the reservoir during well completion operations and remains as a packer fluid throughout the well life. The completion brine is a salt based fluid (usually calcium chloride or a blend of sodium chloride with sodium bromide), with biocide, corrosion inhibitor and oxygen scavenger added to ensure compatibility with metallurgical components.
During periods of gas production and well testing via temporary production facilities on the rig, there will be a requirement to use hydrate inhibitors; typically methanol or glycol. Glycol is also used as a pressure testing medium.
Other chemical options during completion operations include the use of loss circulation materials in the event that fluids are lost down the well. This is likely to be a graded calcium carbonate suspended in a brine.
4.4.2 Options for Hydraulic Valve Control
4.4.2.1 System Options
There are two types of system that could provide mechanical control of valves in the Corrib facilities from the Terminal. Both options involve the use of hydraulic fluid. The closed loop system returns the hydraulic fluid to shore once it has been used to operate a valve. The open loop system involves the discharge of hydraulic fluid to sea at the valve location, once it has been used to operate a valve.
The closed loop hydraulic system is not possible in the Corrib Field because of the length of the umbilical. In order to return hydraulic fluid from the
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subsea facilities to the Terminal, it would need to travel approximately 184 km which would make valve operation extremely slow and potentially unsafe. Therefore, an open loop system has been selected.
4.4.2.2 Fluid Options
Several fluids were considered for use as hydraulic fluid in the Corrib system, including synthetic hydrocarbon compounds and mineral oils. A 50:50 glycol:water mixture was also considered. Although the volumes of hydraulic fluid discharged to the environment from each valve movement are low, the glycol:water mixture is environmentally the preferred option, and was selected for use. Glycol is in the most benign category (group E) of the HOCNF (see Appendix 4.1).
4.4.3 Options for Hydrate Inhibitor
Gas hydrate is a solid ice-like material formed from natural gas and water at specific temperatures and pressures. Hydrate inhibition options were assessed to identify the best inhibitor to protect the subsea facilities and the Terminal from hydrate formation during normal operation, shutdown and start up conditions.
The hydrate inhibitors investigated were:
• methanol;
• glycols-monoethyleneglycol (MEG); and
• threshold inhibitors (THIs).
A detailed comparison of the hydrate inhibitors considered is provided in Table 4.1.
Methanol
Methanol is a very effective and commonly used hydrate inhibitor requiring relatively low concentrations in the gas stream. In addition to its ability to inhibit the formation of hydrates, it can dissolve hydrates which have already formed. Methanol vaporises along with other low volatility components, leaving the remaining water relatively free of hydrocarbons, thereby reducing the impact on the water treatment plant (in the Terminal).
Methanol is classified by the Oslo and Paris Commission (OSPAR) as a PLONOR substance. This is effectively the most benign classification for any chemical used and discharged in the oil and gas industry.
Glycol
Glycol (monoethyleneglycol) represents another commonly used inhibitor. The use of glycol was rejected for a number of reasons. Glycol cannot dissolve hydrates, once formed. Glycol is required in higher concentrations than methanol to achieve the same degree of hydrate suppression. The glycol option would require a 3” pipeline piggy-backed to the subsea pipeline due to the higher volumes required and higher fluid viscosity. The
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regeneration of glycol typically results in dissolved organic compounds (benzene, toluene, ethylene and xylene (BTEX)) remaining in the water phase. Additional water treatment would be required to remove the BTEX.
Threshold Hydrate Inhibitor
Of the two types of THIs available, the Anti Agglomerate (AA) inhibitors were ruled out, due to the Corrib Field’s very low condensate volumes that preclude the formation of a stable water and condensate emulsion. These chemicals would not generate a sufficient degree of hydrate inhibition.
The other type of THIs, kinetic hydrate inhibitors (KHIs), could not be used on their own for the first 8 years of the project, due to their poor effectiveness in higher (above 70 barg) operating pressures. KHIs also have to be used in conjunction with a carrier fluid such as methanol. There is also a general lack of experience of working facilities using KHIs. The environmental effects of KHI use were also uncertain, especially regarding the water treatment effluent/sludges.
Conclusion
The use of methanol as hydrate inhibitor has been recommended, as it provides significant environmental benefits in minimising effluent production volumes and does not produce significant levels of solids. Additionally, methanol provides the most cost effective method of providing hydrate protection over the life of the field.
4.4.4 Options for Scale Prevention
As untreated condensed and formation waters mix, iron hydroxide, calcium carbonate and sulphate solids could precipitate out in the Corrib facilities and present problems to the operations. There is provision to remove potential scaling solids downstream of the slugcatcher at the Terminal. Scale inhibitor injected with the methanol in the Corrib Field will minimise the amount of scale produced. Injection offshore will also inhibit the precipitation of scale within the Terminal. There is a range of scale inhibitors on the market which have high environmental and technical performance. The final choice of inhibitor will be made as soon as any of the wells begin to produce water, and will be dependent upon the exact conditions of the well fluids at that time (temperature, pressure and water content). The choice will also be based on the ability of the water treatment package in the Terminal to effectively reduce the concentration of the scale inhibitor in the waste water. The chemical chosen will also need to be agreed with the EPA.
Methanol can be used to disperse (or melt) hydrate blockages.
Methanol is toxic to personnel at higher concentrations.
MEG is less hazardous to handle than methanol.
Installation of additional ‘piggy back’ line at a significant investment
Potential savings in energy, CAPEX and umbilical pumping requirements.
Limited use with few good examples of commercial applications utilising KHIs.
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4.4.5 Options for Corrosion Protection
4.4.5.1 Internal Corrosion Protection
Corrosion protection is discussed in Section 4.3.2.1. Corrosion inhibitor will be injected into the fluids at the gathering/exit manifold and satellite wells, in a mixture with the hydrate inhibitor. Continual monitoring of the corrosion rates throughout field life will enable adjustments to be made to the concentrations injected. The corrosion inhibitor will partition with the water in the distillation column and then be removed from the water in the water treatment plant, details of this are provided in the Terminal EIS and also discussed in Section 9 of this EIS.
Details of the corrosion inhibitor and its removal from waste water will form part of the IPC licence application for the Terminal.
4.4.5.2 External Corrosion Protection
Coatings and cathodic protection (using sacrificial anodes) are commonly used to prevent corrosion of the external walls of subsea pipework. All surfaces subject to contact with the external marine environment will have cathodic protection using sacrificial anodes, and be coated with durable high integrity coating systems. These coatings are considered to be the primary protection method. The export pipeline will also be concrete coated.
The sacrificial anodes are provided as a back-up measure for the coating, if part of the coating becomes damaged, exposing the bare pipe to the seawater. Where sacrificial anodes are provided, they corrode in preference to the steel. The anodes will be an aluminium-zinc based alloy and are generally present as low resistance electrical bonding straps, or collars, attached to the steel pipe to provide the electrical continuity.
4.4.6 Options for Treatment of Produced Water
The produced water disposal options are discussed in Section 4.2.4 above. Options for treatment of the water before it is discharged are discussed in the Terminal EIS, and in Section 9 of this EIS.
The actual point of discharge will be within Broadhaven Bay, studies to determine a suitable location have recently been completed, more information on these studies can be found in Section 9 of this document.
4.5 Options for Construction/Installation
4.5.1 Offshore Installation of the Gas Pipeline
There are two types of pipelay vessel suitable for laying the Corrib pipeline, an anchored laybarge and a dynamically positioned (DP) laybarge. The vessels differ in their methods of manoeuvring and positioning.
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Anchored pipelay vessels use a series of anchor movements to move along the pipelay route. The anchors are handled by tugs which reposition the anchors to the desired position. The anchoring causes mounds to form in stiff sediments and slightly increases the area of seabed disturbed by the construction activities. It is thought that persistent anchor mounds can impede some types of trawling. While an anchor lay vessel itself does not use a high volume of fuel, the anchor handling tugs contribute significantly to the total air emissions from this method of pipe laying.
Dynamically positioned pipelay vessels use thrusters to keep station. Owing to the large size of the pipelay vessels, the thrusters need to be very powerful. The DP pipelay vessel itself, therefore, has a greater fuel requirement than that of the anchored vessel, however, there are no anchor handling tugs required by a DP vessel. While there is no direct contact between a DP pipelay vessel and the seabed, it does generate propeller wash in many directions. In shallow water, this wash has the potential to disturb seabed sediments and the shoreline, in deeper water this is not be an issue.
Enterprise have selected a DP pipelay vessel for installation of the Corrib pipeline.
4.5.2 Landfall
On the basis of the ecological assessment of the beach, it is considered that conventional open trench supported by sheet piles (cofferdam), if necessary, presents minimal impact and risk. Drilling horizontally under the beach carries risks that drilling mud could escape to the surface. This could compromise the success of the pulling operation. The open trench method has therefore been selected.
4.5.3 Sruwaddacon Crossings
Various construction techniques have been investigated for installing the crossings including open-cut and HDD. The surveys and site investigation information indicate that HDD will not be suitable, on the basis that the permeable nature of the ground could allow drilling mud to escape into the estuary. This eventuality would introduce non-native components into the water and into the sediments. It may also compromise the success of the pulling operation. The selected technique will therefore be open-cut crossings.
A brief description of the two methods is given below.
4.5.3.1 Open-cut
The preferred option for the crossings of the Sruwaddacon is by means of an open-cut trench, employing hydraulic excavators. Details of this method are outlined below:
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• the site will be prepared by stripping the topsoil from all areas adjacent to the estuary banks and ramping the banks down to estuary bed level. The stripped topsoil will be stacked separately from the subsoil within the working area.
• excavation of the estuary bed will then proceed and the excavated material stored adjacent to the trench, within the working area. The prefabricated pipeline section will then be installed in the trench and checked to ensure that a minimum cover of between 1.6 and 2 m exists below the clean hard bed of the estuary watercourse and the top of the pipe.
• initial backfilling and final reinstatement will take place using the excavated sediment.
The estuary banks will then be reinstated to their original profile to the satisfaction of Mayo County Council, the North-West Regional Fisheries Board and the landowners. Any surplus excavated material will be removed from the site to an approved disposal location.
4.5.3.2 Horizontal Directional Drilling (HDD)
With horizontal directional drilling (HDD), the pipeline is bored under the crossing (i.e. estuary crossings) to emerge at a target point on the opposite bank. This is a method, which has been used on many pipelines to cross beneath areas where conventional construction methods could cause unacceptable damage, or where access is severely restricted.
The first stage is to drill a pilot hole using drilling rods. As the drilling proceeds, a drilling fluid, comprising water and bentonite (a naturally occurring clay mineral), is pumped down the centre of the hollow drill rods to lubricates the drilling rods, balances the groundwater and earth pressures and picks up cuttings, before returning to the surface, via the drill hole. The drill fluid is then filtered to remove the cuttings and returned to temporary mud storage tanks for reuse. The position and progress of the drill head is monitored and controlled from the surface using electromagnetic detection equipment.
Drill fluid usage will be monitored at the surface to confirm no significant losses are occurring. Bentonite mud is normally recommended for drilling through groundwater, because it is non-toxic. The composition of the bentonite, the use of any additives and its disposal, will be agreed with Mayo County Council prior to construction.
After the pilot hole is drilled, reaming devices are attached and pulled back through the borehole to enlarge it to the required diameter. Bentonite is injected around the reamer to coat the borehole. It is a thixotropic material and will support the sides of the hole ready for the pipe to be pulled through.
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Finally sections of pipeline are laid out on the opposite bank (‘strung’) in a straight line, and welded together, and coated before being pulled back through the borehole in one continuous length. This minimises the risk of it becoming stuck during the pull.
There is a technical requirement for the drilling mud to be returned from the stringing side during reaming and pull-back operations to the drilling side for reprocessing and re-injection. The options for undertaking this operation are:
a) option 1: laying a small diameter temporary pipeline (welded steel or polyethylene) across the river bed; or
b) option 2: using vacuum trucks to tanker the mud from one side of the river to the other.
Provided it is technically possible, option 1 is preferred.
