Golden Pass LNG

Year constructed:
2009

Major units:
two unloading berths, five full containment storage tanks, vaporization facilities, gas send-out system, ship unloading system, and a natural gas pipeline connecting to existing interstate and intrastate pipelines

Product:
Regasified LNG

Post-project processing capacity:
15.6 million MTA of LNG or 2 billion cubic feet per day of natural gas

Project cost:
$1B

Contractor:
Chicago Bridge & Iron Company N

Located two miles northwest of Sabine Pass, Texas, and 10 miles south of Port Arthur, Texas, the Golden Pass LNG Terminal is situated on the Sabine-Neches Waterway that separates Texas and Louisiana. The LNG terminal will include two ship unloading berths, five full-containment storage tanks, vaporization facilities, and gas send-out and ship unloading systems. The $1 billion contract for engineering, procurement and construction of the project was awarded to Chicago Bridge & Iron Company NV (CB&I) in August 2006. Construction began on the terminal the following month, with operation start-up slated for mid-2009 and total construction completion planned for 2010.

On September 28, 2010, Golden Pass announced that it expected to receive its first LNG cargo during October 2010. The commissioning cargo was en route from Ras Laffan, Qatar via a Q-Flex LNG carrier.

LNG will be shipped to the Golden Pass LNG Terminal primarily from the Ras Laffan 3 and Qatargas 3 projects in Qatar. The terminal will then re-gasify the hydrocarbons. Processing capacity for the terminal is 15.6 million metric tons per year of LNG, which is comparable to 2 billion cubic feet of natural gas a day.

Natural gas will be sent from the Golden Pass LNG Terminal by pipeline to US markets. In addition to the LNG terminal, the project scope includes the Golden Pass Pipeline, which is a 42-inch pipeline that will span 68 miles across four Texas counties and one Louisiana parish to connect with 11 interstate and intrastate pipelines, as well as a short pipeline that will tie-in to the Beaumont industrial area. Start-up for the pipeline coincides with the terminal start-up.

According to the Gulf Times DOHA, the Golden Pass Terminal will receive a third of the gas imports to the US, or 20 million tons, in two to three years of operation start up.

Related Articles

Golden Pass Becomes Fully Operational
May 10, 2011 – Golden Pass LNG Terminal LLC (Golden Pass LNG) announced Tuesday that it has been granted authority by the Federal Energy Regulatory Commission (FERC) to place into service the Phase 2 terminal facilities.

Golden Pass Begins Commercial Ops
Mar 14, 2011 – The Golden Pass LNG Terminal LLC and Golden Pass Pipeline LLC announced Monday that it has been granted in service authority by the Federal Energy Regulatory Commission (FERC) and has commenced commercial operations.

Golden Pass Expects First Cargo Next Month
Sep 28, 2010 – The Golden Pass LNG terminal announced Tuesday that the first cargo to be used for commissioning the facilities is anticipated to arrive during October 2010.

Coast Guard Issues Recommendation Letters for Eight Terminals
Apr 10, 2009 – The U.S. Coast Guard said Friday that it has issued letters of recommendation for eight liquefied natural gas facilities under development on the Gulf Coast.

Startup Delayed for Golden Pass
Dec 19, 2008 – Recently uncovered damage at Exxon Mobil Corp.’s (XOM) $1 billion natural gas import terminal under construction in southeast Texas will delay the facility’s scheduled startup next year.

ExxonMobil: Golden Pass May Face Delay
Dec 12, 2008 – The opening of the Golden Pass liquefied natural gas terminal in the United States will likely be delayed by hurricane damage, while Britain’s South Hook LNG terminal now looks set to open in early 2009, an executive from ExxonMobil said on Thursday.

Port Arthur Pipelines Pass Final Hurdle
Jan 04, 2008 – Two pipelines tied to upcoming industrial projects soon will snake their way through the city with the Port Arthur (Texas) City Council’s stamp of approval.

Port Arthur to Host Hearing on Golden Pass Pipeline Route
Dec 13, 2007 – A 42-inch pipeline running from the Golden Pass LNG facility through Port Arthur, Texas, en route to Calcasieu Parish, La., will be the subject of a Jan. 2 public hearing.

Port Arthur Council Okays Land for Golden Pass
Jul 19, 2007 – The City of Port Arthur, Texas, shed 180 acres of vacant land and another 26 acres of submerged land for the ExxonMobil LNG facility near Sabine Pass.

CB&I Garners LNG Terminal Contract
Aug 01, 2006 – CB&I has been awarded a contract by Golden Pass LNG Terminal LLC for the engineering, procurement, fabrication and construction of a liquefied natural gas (LNG) import terminal located near Sabine Pass, Texas.

FERC Okays Two LNG Import Terminals; Providence LNG Fails on Safety Issues
Jun 30, 2005 – In front of a packed crowd that included some local, state and federal officials Thursday, the last day of Chairman Pat Wood’s term, FERC conditionally approved the Weaver’s Cove LNG import terminal in Fall River, MA, and the Golden Pass LNG terminal in Sabine Pass, TX.

FERC Okays Two LNG Import Terminals; Providence LNG Fails on Safety Issues
Jun 30, 2005 – In front of a packed crowd that included some local, state and federal officials Thursday, the last day of Chairman Pat Wood’s term, FERC conditionally approved the Weaver’s Cove LNG import terminal in Fall River, MA, and the Golden Pass LNG terminal in Sabine Pass, TX.

Interior Takes Aim at FERC’s Assessment of Golden Pass LNG
Apr 11, 2005 – The Department of Interior has said that FERC, in its draft environmental impact statement (DEIS) on ExxonMobil Corp.’s proposed 2 Bcf/d Golden Pass liquefied natural gas (LNG) terminal and associated gas pipeline along the Gulf Coast, failed to adequately assess the project’s impact on endangered species and wetlands.

Source

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US Freeport LNG set to re-export cargo by early Oct

By Edward McAllister

NEW YORK, Sept 22 (Reuters) – The U.S. Freeport liquefied natural gas terminal in Texas is set to re-export another cargo of LNG in the next two weeks to take advantage of higher-paying markets in Asia or Europe, a company representative said on Wednesday.

A tanker is expected to load up and transport LNG overseas at the end of September or beginning of October, said Mark Mallett, Freeport’s vice president of operations and engineering.

The Al Ruwais LNG tanker, which recently offloaded at the Altamira terminal in Mexico, headed north toward Freeport this week and was seen about 100 miles (160 km) from the terminal on Wednesday, according to AISLive ship tracker on Reuters.

“We have received no official notification from our customers if this is the ship, but we expect to load a tanker by early October, maybe in late September,” Mallett said.

This would be the latest in a growing number of re-export deals done since the terminal received approval in May 2009 to import LNG, store it and export later to more attractive markets overseas.

It is a symptom of over-supply in the U.S. gas market and the subsequent weak prices which have deterred shippers from sending much LNG to U.S. terminals this year.

On Thursday, U.S. gas futures, just below $4 per mmBtu, were about $2.80 below British gas prices and about $5 below Asia spot LNG prices, making it profitable for traders to send cargoes to Asia from the U.S. even after shipping costs. <0#NG-NGLNM=R>

The last re-export cargo left Freeport at the beginning of September for Japan in the Excalibur tanker, after Freeport customer ConocoPhillips (COP.N) sold a cargo to Citi Group (C.N). [ID:nN31238805]

Cheniere Energy’s (LNG.A) Sabine Pass terminal in Louisiana, which also has re-export capabilities, could make similar use of an empty tanker.

Sabine Pass and Freeport — currently the only U.S. terminals that can re-export LNG — have together exported 9.7 bcf of gas since they received the approval last year, according to Waterborne Energy analysts in Houston. Sempra Energy‘s (SRE.N) Cameron LNG terminal in Louisiana has recently applied for a re-export license.

Cheniere has gone one step further, planning to build a liquefaction plant that would export domestically-produced gas. Freeport LNG is also considering its options in that area, Mallett said. (Reporting by Edward McAllister; Editing by Marguerita Choy)

Source

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Introduction to Geoprober Drilling System

Geoprober Drilling has developed a low cost exploration drilling system which can be deployed from a mono hull vessel.

Uploaded by geoproberdrilling on Sep 3, 2010

By Tony Bamford, Geoprober Drilling

Introduction

Geoprober has developed a deepwater exploration drilling system deployed from a cost effective monohull vessel (Figure 1). The company is designing, building and testing, proprietary surface and subsea drilling technology. Although funding was provided through a Joint Industry Project with Chevron and Statoil, the technology resides in the company.

By, establishing the well in one trip, reducing hole size and operating from a monohull vessel, the cost of an exploration well can be reduced by over 50%.

The unique feature of the system is that all subsea equipment to establish the well, including the conductor, template, wellhead and even the subsea BOP are connected together on the vessel. This assembly known as the Geoprober Shut Off System (Geo-SOS) is lowered to the seafloor on 7-5/8” casing with a removable drill bit.

Figure 1 – Overview of the Geoprober System – Detail of the Geoprober Subsea Shut-off System



The Geo-SOS is jetted in so that the conductor typically (13-3/8” casing) supports the seafloor equipment. Then the 7-5/8” casing is drilled down to the surface casing setting depth where it is cemented in place.

The 7-5/8”surface casing used for drilling also becomes the top tensioned riser with a near surface BOP. All well control issues handled at the surface. Subsea equipment is for an emergency shut off only.

The “Finder well” design

With the Geoprober “Finder well” the basic bit and casing sizes are fixed. This is illustrated in Figure 2. On first thoughts this may seem a little restrictive to reaching certain well objectives. However it gives the explorer a different paradigm to work with. Where in the world is there prospective acreage in water depths of up to 3,000 metres and where the reservoir lies less than 3,000 metres below the mud line?

Figure 2 – The Geoprober basic well configuration

Finding the most prospective deepwater areas of the world where exploration and appraisal wells drilled for less than 40% of the current costs could really add value to your portfolio. There is an exponential cost to drilling wells with increasing overpressure. The Geoprober system is not a HTHP drilling system.

However it is recognised that some contingency must be in place in the event of hole problems. Geoprober plans to address this issue through the use of expandable liner systems that are currently available on the market. This is illustrated in Figure 3. Further contingencies can be provided through the use of the Caledus slim well liner system.

Figure 3 – Extending the well depth envelope

Where in the world are the targets in a combination of 6000 m of water and formation? Here is a published example exploration portfolio from Shell in the GOM in Figure 4. It can be seen all the prospects below the red line could be accessed by the Geoprober Finder well system.

Figure 4

Figure 5 illustrates where the exploration objectives satisfy the well constraints (Perdido fold belt) and where they don’t (Mississippi Fan Fold Belt) For the latter you need multiple casing strings and HTHP technologies to reach your objectives.

Figure 5 – Contrasting exploration plays in the GOM

Where are the savings?

So where are these savings? With the Geoprober system in this well example (Figure 6) in 8,000 ft of water you have run the BOP, set the surface casing and run the riser on day 3. With a conventional deepwater rig this is done in 10—12 days.

Also with drilled in casing you can push the envelope deeper since the small annular clearance gives better control of shallow gas (a bit like a pilot hole).

The well can be drilled with Coiled Tubing or jointed pipe. Coiled tubing with fibre optic and power conductors inside will dramatically increase data rates.

Rapid spooling through the water column increases the opportunities for data acquisition.

Figure 6 – Time Savings Depth versus Days

We took a typical GOM well and calculated the AFE and the savings based on the market in 2004. The numbers may be changed but the differential is still the same.

Currently there is a real business opportunity where monohull vessels have been overbuilt in the 2008 boom. If we could charter a vessel on a long term, right now this differential could increase much further.

Figure 7 shows the calculated savings by category. Transport is less since the need the same supply vessels are reduced. The rig rates are dramatically different, you have to pay a lot more to run that large diameter riser in deepwater. The slim hole savings on mud volumes are obvious. The total costs for a conventional 5th generation deepwater semi-submersible was $13.9 mm on a dry hole basis. The same well drilled with the Geoprober technology was $5.7 mm on a dry hole basis. This represents a 59% Savings.

The environmental impact is a major consideration for Statoil, the project sponsors. Statoil commissioned an independent environmental impact study from based on a typical well in Norway using the life cycle methodology. The assumption being both the conventional and Geoprober wells were drilled in 15 days.

Statoil’s conclusions were:

• Replacing a conventional semi-submersible drilling rig with a Monohull vessel, allowing savings in fuel use, estimated at ~70%.
• Smaller well and riser radii reduces the volume of cuttings and OBM significantly (Conventional 1 600 m³ OBM, Geoprober 240 m³)
• Smaller well radii also reduces steel requirements for casings (Conventional 150 tonnes steel, Geoprober 60 tonnes)

Figure 7 – Analysis of well cost savings

The Geoprober Technology Drivers

The Geoprober technology development was initially focussed on drilling-in the surface casing. With current subsea wellhead systems this is not possible since the casing string is usually attached to the wellhead that must always land out at a fixed point i.e. the sea floor. The Geoprober wellhead system illustrated in figure 8 is designed with two hydraulically operated grippers and two extruding wellhead seals. This enables the casing to be drilled in and suspended at any depth. This is ideal in an exploration well, where you will not know in advance with any precision where the surface casing needs to be set.

The upper gripper provides the mechanism for running the the Geoprober Subsea Shut Off System (Geo-SOS) to the seafloor on 7-5/8” casing.

This gives rise to the second technology driver namely to reduce the weight of Geo-SOS to around 30 tons this compares with a large 350 ton Subsea BOP stack typical of a 5th generation deepwater rig. The reduction in weight deployed to the seafloor means that the monohull vessel does not have handle the heavy loads of a large diameter riser (typically 19-1/2”). This is in part because a surface BOP is employed to carry out all well control functions. The Geoprober Subsea Shut Off System at the seafloor (Figure 8) is only there to isolate the wellbore in the event the vessel cannot maintain its position over the well or weather conditions require disconnection at the seafloor.

Figure 8 – The Geoprober wellhead system – lower part of the Subsea Shut-off System

The second aspect of operating in 3,000 metres of water is the problem of controlling the subsea equipment. At these depths, the ambient seawater pressure means that conventional BOP control systems, based on stored energy in hydraulic accumulators, do not function efficiently. For this reason Geoprober changed the control philosophy from conventional BOP control. First power is provided by a set of conventional batteries operating local hydraulic pumps. Second the control system is based on the principles used in the aircraft industry where “Triple Modular Redundancy” or TMR is used for safety critical equipment. This is based on a hardware voting system and is qualified to the exacting Safety Integrity Level 3 (SIL 3) used in that industry.

Figure 9 illustrates the operating principles. Figure 10 shows prototype equipment under test.

Figure 9 – Geoprober control system operating principles

Figure 10 – Prototype testing at Geoprober Drilling

It can be seen that the Geoprober Subsea Shut Off System is a key safety critical element. Its ability to disconnect instantaneously at the sea floor must be beyond doubt. Hence Geoprober had to prove several independent methods of communicating to the seafloor via ROV and acoustically. The main disconnection device is a rotary cutting tool that clean cuts the drilled in 7-5/8” casing/ riser. If this fails there are two shear rams to perform the same function. It was shown in the testing regime that the shear rams can sever both the 7-5/8” casing riser and the drill string or casing being run inside. It was also shown that each battery set could provide enough energy to sever the casing 6 times within the required time of 45 seconds.

How Safe is Safe?

Following the “Deepwater Horizon” blowout in the GOM, the industry is rightly scrutinising every aspect of the well design and the equipment used to control the well. On the face of it seems this is not a good time to be introducing new drilling technology. I beg to differ.

Deepwater Drilling is done with a conventional subsea BOP and large bore riser. This means that when handling a “kick” it is very important to shut the well in early and circulate through the choke line. If the kick goes undetected and a volume of gas enters the riser, it cannot be contained, since there is only a low pressure diverter at the surface to direct the gas flow overboard. One hopes that the kick can be detected early enough, history however suggests otherwise. The riser unloading exponentially is all too common.

With a shut-off system at the seafloor and a high pressure casing riser culminating in a near surface BOP, the pressure can be maintained at the surface. This kick can be circulated with the required back pressure or otherwise “bullheaded” back into the formation.

Further more drilling a slim exploration, the restricted wellbore geometry reduces the flow potential from the reservoir making exploration inherently safer.

Another safety aspect of a near surface BOP is that the diverter can be set up underwater. This is so that even if there is a total failure of the near surface BOP, diverter lines can be arranged to direct hydrocarbons away from the vessel.

Vessel Handling Equipment

As the project developed, it became clear that handling the heavy loads on the vessel was a potential showstopper. Even with the slim well design based on the 7-5/8” drilled in riser, the loads exceed those normally handled from relatively small monohull vessels. Typically handling towers on vessels are used for well intervention and have a capacity of 100-150 tons.

Geoprober’s technology is based on the “Reverse Derrick” principle. Figure 11 shows the vessel moonpool from underwater and how heavy loads are suspended and handled below the keel level of the vessel. This greatly improves the vessel stability.

Figure 11 – Underwater view of the moonpool showing the Tension Frame and Geoprober Subsea Shut-off System (Geo-SOS)


Figure 11 pictures the Geoprober Subsea Shut-Off Sytem (Geo-SOS) complete with conductor and template just after launch from the Tension Frame. In a conventional derrick, these cyclic loads must be reacted through the derrick legs. These adverse loads can be alternately tensile and compressive, especially when the vessel rolls.

The Reverse Derrick Principle uses a combination of cylinder based riser tensioners and dual hoisting winches as depicted in Figure 12.

Figure 12 – Riser tensioning cylinders and dual winches laid out over the moonpool

The Tension Frame illustrated in Figure 13, supports the underwater elevators. The underwater elevators are used, to suspend the riser, when lowering it joint by joint, below the moonpool.

The winching system is connected to the tension frame corner sheaves with wire rope and moves the latter up and down as required. The winching system ensures all the loads are reacted at keel and deck level, while the tensioning cylinders compensate for the movement of the vessel. 7-5/8” casing riser joints are lowered on the underwater elevators. Then the casing riser is suspended from the rig floor on conventional slips. The underwater elevators release the load and strip back over the pipe to pick up the next joint.

The underwater elevators fit into a square Tension Frame which is sized to travel in and out of the moonpool. It has sheaves on each corner that connect it with a double fall wire rope to the tensioning and winch system on the deck.

Figure 13 – The Tension Frame with the Underwater Elevators installed (grey)


In this way, the vessel derrick or tower no longer has to handle the heavy loads. It can be a much lighter structure and be especially equipped to handle jointed pipe or coiled tubing. This is illustrated in Figure 14.

When the underwater elevators are removed, the Tension Frame has the capability to suspend and run BOP’s and subsea trees through the splash zone. Extensive hydrodynamic riser modelling has been carried out to prove the operating envelope of the system. The load cases identified have been subjected to structural modelling and clearly demonstrate the advantages of distributing the loads at keel and deck level.

Figure 14 – The complete Geoprober handling system installed on the vessel

Slim Well Formation Evaluation

Considerable effort in the project was devoted to identifying slim well logging and formation evaluation tools. The range and availability of these tools on the market has increased considerably since the start of the project.

A well testing system based on deploying coiled tubing as the test string was identified as a future direction.

Commercialising the Geoprober System

The current status of the project is that the R & D work has been completed. Geoprober are working closely with Statoil to identify opportunities to deploy the technology offshore in a phased approach integrated with other contractors. The expected capital requirements are as follows:

• Detailed engineering build and test the Geoprober Subsea Shut-off System, near surface BOP: $10.5 million. This is scheduled for 18 months
• Detailed engineering build and test the Geoprober vessel handling equipment in conjunction with Bosch Rexroth suppliers of the drive and control systems: $50 million. This is scheduled from start for 20 months.

Conclusions

It goes without saying that Finding Petroleum in deepwater is an expensive and risky business. The Geoprober system can be built and introduced to the field for less than the cost of many deepwater wells. The expected ratio of day rates for 5th or 6th generation deepwater rigs to the Geoprober system is in the order of 3:1.

By carefully selecting the deepwater exploration portfolio, operators would have an opportunity of drilling many more exploration and appraisal wells to increase the chances of success and reduce the cycle time between discovery and production.

Acknowledgements

Geoprober Drilling would like to thank the project sponsors Statoil and Chevron for their support in developing the technology. Original

Article Original

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