Industry News - Offshore Engineer Reports - Frontier no moreFrontier no more
from: Offshore Engineer
by: Jennifer Pallanich
Monday, April 07, 2008
The eastern Gulf of Mexico was a frontier area with the December 2001 discovery of Merganser. A year later, Vortex claimed headlines. Operators reported three more finds each in 2003 and 2004 and another pair in 2005. Individually, water depths ranging from 7850ft to over 9000ft and distance from shore made each non-commercial. But by working together, the independent operators, a hub owner, and their many partners and contractors have brought the 10 fields onstream and broken some serious depth records while they were at it. Jennifer Pallanich reports on the technology the Independence Hub team applied to overcome the challenges.
Combine one part depth and two parts lack of infrastructure in the eastern Gulf of Mexico, and you have a recipe for a complex development. Independence Hub carried a $2 billion price tag.
Then again, if the deepwater players in the Eastern Gulf hadn’t teamed up, none of the 10 gas discoveries would have been commercial.
‘That’s a lot of resource that would have been stranded out there,’ Susan Holley, Anadarko’s general manager for Eastern GoM, says of the estimated 2tcf reserves in place. The hub, when onstream at full capacity of 1bcf/d, will supply 10% of the Gulf ’s gas output and nearly 2% of the overall US gas supply. The hub is designed for a 20-year lifespan.
‘People don’t consider the Gulf of Mexico as having frontier areas,’ Holley says, noting the Eastern Gulf is most certainly a frontier area at 9000ft water depth. ‘You have a lot of world records associated with the water depth you’re working in.’
Paul Beer, Anadarko’s subsea project manager for Independence hub project, says an AUV route survey early in the project provided some lessons learned that drove home clearly the fact that the project would break depth records.
‘This was the first actual time that we realized we’re going deeper than anyone else has gone,’ Beer says.
If depth and lack of infrastructure created some hefty project challenges, planning and flexibility (and rising gas prices) helped the project happen, maybe even painlessly at times.
Planning was vital.
Hundreds of thousands of hours went to a conceptual study, a conceptual design, and detailed engineering. Another 10,000 hours or so were dedicated to the expansion when the team decided to upsize the hub from the planned 700mmcf/d to 850mmcf/d and then to 1bcf/d.
Technip was contracted to build a scale model of the facility destined for Mississippi Canyon block 920; engineers used the model frequently during the planning process to determine the sequence of installation activities.
Flexibility meant being able to work despite the infamous Gulf of Mexico loop current. To ensure the project was always moving forward, several vessels were on call at all times.
‘There are always things that affect your installation plan,’ Don Vardeman, Anadarko’s vice president for worldwide facilities, says. ‘With as much work as we had to do . . . we could divert those vessels to other work.’
Anadarko’s simultaneous operations coordinators determined what work would be done based on safety and priority.
‘There was quite a choreographed dance between the contractors and several oil companies’ to make efficient use of Heerema’s Balder and Subsea 7’s Toisa Perseus, says Mike Gann, Anadarko’s project construction engineering advisor for worldwide deepwater operations.
‘There were a lot of ducks swimming real fast under the surface of the water to make it look well choreographed,’ Vardeman says of the installation. This was especially impressive, he says, as each change can affect more than one area of the work.
Flexibility was increasingly important with high day rates, limited rig and resource availability, shifting loop currents and a watchful eye on hurricane season.
‘Our contractors showed us a lot of flexibility,’ Beer says.
But that flexibility only reaches a certain point.
‘We had less flexibility later in the game than we had earlier,’ Peter Stracke, StatoilHydro’s asset manager, says, since each job accomplished meant one less to choose from.
There’s no way to avoid working during hurricane seasons when the project lasts as long as it took to bring Independence Hub onstream, Vardeman says.
‘If there’s anything more difficult than predicting the weather, it’s predicting the currents,’ Vardeman says.
On that note, Gann hopes to see better loop current forecasting in the Gulf of Mexico in the future.
Pat Watson, Anadarko’s drilling manager for the Gulf of Mexico and international deepwater drilling, estimates the thorough planning process meant Anadarko suffered less than 2% downtime because of the loop current.
‘We were able to time things out, spread things out, move rigs to other areas, and avoid that kind of downtime,’Watson says.
Standard equipment helped smooth over what could have been one long series of hiccups. Each operator could have chosen a different brand for each item, but the team decided to go with standard FMC Technologies trees and connection systems, Aker Kvaerner Subsea controls and umbilicals, and Roxar wet gas flow meters.
‘That kept us from having five varieties of everything out there,’ Vardeman says. ‘We’d have lost all the synergies.’
Stracke agrees: ‘In the back of everyone’s mind was “It really would help if everyone went with the same vendor.”’
While the project may be the deepest to date, Stracke says, vendors paved the way since many have been designing items that could work in 10,000ft of water.
‘We didn’t have to start from scratch as some people thought we would,’ Stracke says.
There were some small challenges, though, such as the AUV’s batteries and the trip times associated with that much water.
Once the battery issue was sorted out – apparently the pressure was delaminating the batteries – the C+C Technologies AUV performed its tasks, Stracke says. ‘The wow factor to me was that an unmanned sub like that can go away, do all that work and come back again.’
‘The sheer time it takes to go up and down makes a difference to the project,’ he continues. ‘Once an ROV gets down there, you tend to leave it down there and work it.’
Often, Stracke says, the rope used to lower equipment to the seabed weighed more than the equipment itself. ‘Those things can surprise you a bit.’ But, he adds, he’s been in the subsea industry for so many years that he wasn’t surprised at all that the project was doable.
Stracke says the project team invested well when it chose the high-end vessels for installation. ‘We tended not to skimp on stuff like that,’ so there were no points when the team wished it had done something differently. ‘You might, though, if you’d used a marginal vessel.’
Lights, camera . . .
Atlas, Altas NW and Mondo came onstream first on successive days, starting 19 July. Atlas was the first Lease Sale 181 well to begin production.
‘By day four, we were at 150mmcf/d,’ says Bob Buck, Anadarko’s senior staff production engineer for Gulf of Mexico deepwater operations, calling startup uneventful. ‘All your homework definitely pays off.’
As of early October, the hub was producing more than 500mmcf/d from nine wells, and the additional wells were expected to come on line by year’s end.
Looking back on the efforts of the project teams about a month after Atlas went onstream, Gann says there are several keys to success in a project like Independence Hub: planning, focus on common goals, the right people, perseverance and workability.
‘There’s the potential for conflict in projects, particularly when you have different companies working together,’ Gann says. ‘Everyone was very professional and kept a “best for project” attitude throughout.’
The project’s setup made that crucial for a relatively bump-free ride. As hub operator, Anadarko leads the Atwater Valley Producers Group that operates the various fields. AVPG partners include Devon, Eni and StatoilHydro. Enterprise Products Partners holds 80% and Helix Energy Solutions holds 20% of the hub itself.
Coordination was central, Gann says. ‘It’s rare to find this level of coordination in our industry.’
The development leaves room for growth. Space exists for additional risers at the platform, and there are spots for subsea tie ins as well.
‘That makes it real inexpensive to tie another well in,’ Vardeman says. ‘There’s a lot of subsea plumbing and electrical connections and umbilical connections that provide us with considerable flexibility on how we operate as well as how we expand.’
Holley is one of many thinking about eastern Gulf of Mexico expansion, especially with the newly opened acreage that was made available in the recently held Lease Sale 205 and that will become became available in the eastern Gulf of Mexico Central Lease Sale 224, scheduled for March 2008.
‘We’re looking at what’s going to keep this facility full for years to come,’ Holley says. OE
Let it flow
Miles and miles of flowlines connect trees to the Independence Hub – 192.7 miles, to be exact.
Some of the wells are as far away as 45 miles from the hub. Controlling a well that far away is ‘a real technical achievement,’ Susan Holley, Anadarko’s general manager for eastern Gulf of Mexico, says. ‘Every aspect of the project . . . set records due to the technologies used, the water depth, the size and the magnitude.’
The increasing tieback distance is a testament to advances in production technology, says Don Vardeman, Anadarko’s vice president for worldwide facilities. Initially, the project team planned to put the hub in Atwater Valley block 85, but the distance from Spiderman in DeSoto Canyon blocks 620/621 was a concern. Using Petroleum Experts’ Integrated Production Model (IPM) software, the team ultimately put the hub at Mississippi Canyon block 920. ‘Nobody suffers from lower reserve recoveries at that location,’ says Bob Buck, Anadarko’s senior staff production engineer for Gulf of Mexico deepwater operations.
The IPM also showed that the originally planned 700mmcf/d capacity was a bit on the low side, so the project team bumped the planned hub size to 850mmcf/d. Later, the team decided to jump up capacity to 1bcf/d to accommodate additional natural gas production from the three additional discoveries made in the area after the project was originally announced.
The project team also used IPM to determine whether single or dual flowlines were most desirable for each field. In one instance, Buck says, several alternatives were available for serving Spiderman and San Jacinto, including individually tying each back to the hub or the chosen option of tying San Jacinto into Spiderman with a single 8in 7 mile flowline and tying the pair into the hub with 10in and 8in dual 25 mile flowlines. The model eased concerns about that design compromising Spidy’s output, Buck says. ‘We looked at this scenario and realized we would save a tremendous amount of money. Tying San Jac into Spiderman and then running the dual flowlines from there to the hub resulted in cost savings of $25 million.’
Due south of the San Jac and Spiderman fields lie the Atlas, Atlas NW, and Mondo fields. This combination represents the largest well count on a single flow line in the development.
Buck says Anadarko decided to run all three wells on the same flowline based on the model and characteristics of the fields in question. The Atlas-Atlas NW-Mondo configuration is three wells flowing into a single 8in flowline. It’s 11.7 miles from the hub to Mondo, 10 miles from Mondo to Atlas NW, and 3.2 from there to Atlas. To optimize reserves recovery under this design as well as the other wells, Buck says, the plan is to add compression and lower pressure topsides. ‘Mondo has some recompletion zones that we’ll go to at some point,’ Buck says, adding that Atlas and Atlas NW have one zone each and will deplete sooner than Mondo. With its multiple zones, Buck says, the estimated lifespan of Mondo is at least a decade.
Further south lie the Vortex, Jubilee and Cheyenne fields, which feature four wells. Dual 8in and 10in flowlines serve Vortex and Jubilee and dual 8in lines run from Jubilee to Cheyenne. From the hub to Vortex is 24.4 miles. The Vortex to Jubilee line is 6 miles, and it’s 14.7 miles from Jubilee to Cheyenne.
The Q and Merganser fields are west of the Atlas area. Q has one well flowing into a single 8in line that runs 10.3 miles from the hub to Q. Merganser has two wells flowing into a single 8in flowline, and it’s 13.8 miles from the hub to Merganser.
Of the 192.7 miles total of flowlines, there are 141 miles of 8in lines and 51.7 miles of 10in lines.
Filling all coffers
Each well jumper has subsea wet gas meters to monitor gas, condensate and water rates from each well. Buck says these meters, the largest application of such meters in the Gulf, deliver the information to the platform before the production actually arrives there. Subsea, Roxar meters measure at each wellhead ahead of the comingling in the pipeline to meet MMS royalty requirements. Additionally, each flowline from each field has its own allocation separator topsides, says Enterprise vice president for offshore commercial development Jim Guion.
‘Their production is measured right there, so that’s how they sort out how much production comes from that field to the facility,’ Guion says.
UMBILICALS/MOORINGS
A balancing act
Anything that winds up on an offshore platform must bear its weight – or go on a diet. Independence Hub designers found several ways to slim down offshore demands to meet the challenges of installing and producing from 9000ft of water.
The depth of the fields called for designers to scrutinize the traditional when it came to umbilicals. In 9000ft of water, armored umbilicals simply weigh too much. There was another option, however, using carbon fiber rod technology that Aker Kvaerner Subsea had developed. AKS used the technology from its composite tendon product to develop its carbon fiber enhanced subsea umbilical design that was given OTC ‘Spotlight on Technology’ billing in 2005.
As AKS was preparing its umbilicals proposal for the Independence Hub team, Robert Schriefer, Aker Kvaerner Subsea’s sales manager for umbilical systems, says the idea came about to employ the company’s recently developed carbon fiber rod technology. ‘It was very innovative,’ Schriefer says of the transfer of technology.
Paul Beer, Anadarko’s subsea project manager for Independence hub project, says it worked out well that AKS saw the umbilicals as an additional application for the carbon fiber rod technology because the armored umbilicals needed to deal with the water depths were not an attractive option, weight-wise.
‘The carbon rods used in the umbilicals gave us the strength characteristics we needed without giving it the extra weight,’ Don Vardeman, Anadarko’s vice president for worldwide facilities, says.
The patented carbon fiber rod technology increases the axial stiffness of the umbilical while being nearly neutrally buoyant, Schriefer explains.
Within an umbilical, steel tubing provides the axial strength. As mainly steel weight drives the top tension, further steel armoring is inefficient, adding weight and ‘eating up’ the stiffness contribution, Schriefer says. To overcome this problem, AKS developed deepwater steel tube umbilicals with increased axial stiffness through using carbon fiber rods. The carbon fiber rods are ideal for axial stiffness enhancement as they have a Young’s modulus close to the value of steel but with only a fraction of the weight, Schriefer says.
Carbon fiber rod technology provides two additional benefits, Schriefer says, noting that the technology allows the weight budget of the host to be dedicated to other kit and it improves the overall installability of the umbilical.
‘Based on initial analysis, the use of traditional umbilicals in this water depth could exceed the acceptable strain levels in the umbilical electrical cables,’ Beer says.
The choice came down to steel or carbon fiber rod technology.
‘The difference between carbon fiber rods and steel is mass and weight in water,’ Schriefer says.
In ultra-deepwater, that meant more steel to meet the demands of the subsea environment or going with the new option. With carbon fiber rod technology, Schriefer says, ‘We’re not eating up the weight budget of the host.’
The carbon fiber rods are in the dynamic umbilical sections and not in the static sections, Beer says. The carbon rods increase the axial stiffness of the umbilical.
‘We’re only using 12% of the carbon fiber rod load-carrying capacity.’ Using traditional umbilicals, Beer says, would have stretched the load-carrying capacity to 90%.
It helped that the carbon fiber rod technology was competitive commercially from use in other industries. ‘It was kind of unusual for new technology,’ Vardeman says. ‘The initial installation usually involves a premium.’
But then, the hub partners had just placed the largest subsea umbilical order to date. The fields represent the first use of carbon fiber rod technology in subsea umbilicals. AKS manufactured the 132 miles of umbilicals at its Mobile, Alabama, facility.
Like some projects before the Independence Hub, the umbilicals also had buoyancy modules on them about 300m above the seafloor. Without the buoyancy, Beer says, the floating production platform vessel motions were predicted to cause potential compression of the umbilicals at the touch-down point during 1000-year storm events. It was the first time Anadarko had had to add buoyancy to the umbilicals, he adds.
Trelleborg CRP manufactured the umbilical buoyancy modules in the UK.
Schriefer says the first order vessel motion characteristics of the host vessel are a main consideration in whether buoyancy modules are required. ‘The various production platforms in common use today have distinctly differing heave motion characteristics. For example, semisubmersible platforms or FPSOs exhibit larger heave motions than, for example, a TLP or a spar.’
When determined through dynamic analysis that buoyancy is required, a relatively short section of about 100m is sufficient to de-couple the effects of platform motion on the umbilical response in the touchdown region, Schriefer says.
The design phase of the steel catenary riser (SCR) presented different challenges.
Designing the SCRs for strength and fatigue life was challenging because of the movement of the hull and the variable polyester mooring stiffness, says Mike Gann, Anadarko’s project construction engineering advisor for worldwide deepwater operations. ‘The design of the SCRs overcame many first-of-a-kind technical issues.’
It took the team about nine months to become satisfied that it had correctly engineered the SCRs, Gann says.
Tie down
The hub represents the third application of polyester mooring in the Gulf. It follows in the footsteps of BP’s Mad Dog spar in 4500ft water depth in Green Canyon block 782 in 2004 and Anadarko’s own Red Hawk cell spar in 5300ft water depth in Garden Banks block 877 in 2004.
At Independence Hub, each of the 12 mooring legs is 11,000ft long, and it took Heerema’s Balder three weeks to install the synthetic mooring lines after it had pre-installed the suction piles, Gann says.
Using neutrally buoyant polyester moorings made sense, given the project’s depth in 8000ft waters, Gann says.
Benefits from using the polyester mooring included removing that mooring load from the hull and diverting hull capacity to other payload, he adds.
The first Gulf of Mexico deepwater field to use polyester mooring supports that. According to BP, Mad Dog’s synthetic lines gave the spar over 1000 tons of reserve buoyancy to support future production growth.
On the other hand, polyester mooring stretches slightly, or creeps, when loaded. To design around that, Gann says, the rope is ‘overstretched’ during installation, which removes the potential for stretching during the field’s lifespan but without damaging the integrity of the mooring system. Just to be sure, though, the US MMS requires testing of polyester mooring. Gann says the hub can accommodate the testing schedule, which requires removing and analyzing 45ft segments of the rope at 30-month intervals, or more often with strong storms or hurricanes in the area.
DRILLING & COMPLETION
Downsizing D&C costs
When Anadarko first did the math on its 12-well drilling program, it estimated $21 million and 35 days per well for a dry hole case, Pat Watson, Anadarkofs drilling manager for GoM and international deepwater drilling, says.
After drilling the first few wells and adapting the program, the drilling became faster and cheaper. By the end of the drilling program, Anadarko was spending an average of $13 million drilling each well. The drill, evaluate, case and suspend costs came in 22% under budgeted figures,Watson says. And in terms of time, each well was also taking 24 days to drill, evaluate, case and suspend.
'We got to a point where we just couldnft get any faster,' Watson says.
Anadarko used Transoceanfs Deepwater Millennium for its completions work. But the rig wasnft set up for that so first Anadarko had to modify the rig, including:
- installing a LARS/IWOCS unit, which included reinforcing the deck to deal with the weight, so the IWOCS umbilical could be deployed from the side rather than through the moonpool;
- reconfiguring the BOP stack for completions;
- adding well test equipment, a flare boom and other equipment; and
- adding additional accommodations for the extra personnel.
Randy Atwood, Deepwater Millennium rig manager, said the crews working the project showed 'significant time savings, continuous improvement in completing 12 wells, and world-record water depths for completions operations between 8000ft and 9000ft'.
According to Atwood, Anadarko's integrated completions project team worked closely with the Deepwater Millennium and service company personnel to pre-plan, execute and continuously improve operations by applying what was learned from well to well. 'In short, our teams were able to complete the project safely and several months ahead of schedule,' he says.
The process improved at every step of the 12-well program, Kevin Renfro, Anadarko's production engineering manager for Gulf of Mexico deepwater completions/production, says.
One of the big money savers,Watson says, involved switching from dye markers to hollow polymer beads when pumping cement in the riserless hole section. By using the polymer beads ahead of the cement,Watson says of the method he pioneered, it was possible for the ROV to hone in on the beads as they appeared at the seafloor. The improved spotting ability meant less excess cement pumped downhole,Watson adds.
The rig drifted with the BOP stack still lowered when applicable,Watson says, and other savings involved reusing water-based MI-Swaco Ultradrill mud down to the 13 5/8in casing point before switching to synthetic Nova Plus mud.
'There's no abnormal pressure out here, we found out later, which allowed us to drop the 16in casing out of the drilling program,' Watson says.
Because of rig costs and environmental concerns, it was imperative to plan well, Renfro says. He says the team worked to complete activities before it became part of the critical path in order to save time and money. For instance, the team used the Casey Chouest anchor handling vessel to install the trees. 'That made a big difference,' Renfro says.
Always, the loop current had to be considered.
'We had built in enough flexibility,' Renfro says.
'We could pick which [site] we wanted to go to.'
'The team averaged 25 days per completion. All the different time-shaving activities helped reduce completion time without compromising quality or the environment, Renfro says.
The team also pre-assembled the packers and found a safe way to lift the 90ft packers without bending or breaking them. 'It just saved a bunch of time,' Renfro says.
COLLABORATION
An Enterprising approach
In the beginning, it was just Merganser, a Kerr-McGee-operated frontier find.
That’s when midstream company Enterprise started paying attention. They began discussing development options with Kerr-McGee, which Anadarko bought in 2006. More producers drilled wells in the Mississippi Canyon and Atwater Valley areas. ‘We felt there was enough synergy to support a development,’ says Jim Guion, Enterprise vice president for offshore commercial development.
Collaboration followed, culminating in an agreement in which several producers banded together with Enterprise to develop the 10 fields. Under the agreement, Anadarko operates the platform, which is owned 80% by Enterprise and 20% by Helix. Anadarko has reserved 61% of the capacity on the hub, Eni has 20%, StatoilHydro has 12.5% and Devon has 6.5%.
‘It’s a major extension on the hub and spoke approach,’ Don Vardeman, Anadarko’s vice president for worldwide facilities, says.
The Independence Trail pipeline, 100% owned and operated by Enterprise, connects the hub platform to onshore markets via an interconnect with the Tennessee Gas Pipeline at Enterprise’s West Delta block 68 shallow-water manifold platform. The 134 mile pipeline is 24in in diameter and can transport up to 1bcf/d of dry gas. The company owns seven other platforms in the Gulf of Mexico, Guion says, and owns over 1000 miles of gas pipelines and 925 miles of oil pipelines.
‘Enterprise’s real interest is in the infrastructure,’ Guion says. ‘The platform assets allow us to build and support transportation infrastructure into these frontier areas that don’t have existing infrastructure.’
The Enterprise approach of installing infrastructure in fledgling areas establishes a basis for growth. With the addition of a pipeline and platform facilities, Guion says, areas that once were uneconomic become attractive to operators.
Enterprise is evaluating several prospective areas for possible infrastructure installation, Guion says, adding the company is in talks with several producers on various oil and gas opportunities in the Gulf. He said the south Green Canyon and north Walker Ridge area has many of the characteristics Enterprise seeks in a hub-type project.
This project’s success suggests that more might follow. ‘Our management embraces this as the way to go about ultra-deepwater developments,’ says Mike Gann, Anadarko’s project construction engineering advisor for worldwide deepwater operations, adding combining resources benefits many. ‘We see it as a real opportunity to develop things we might otherwise not be able to develop.’
Under the commercial model for Independence Hub, Enterprise funded all of the export pipeline and 80% of the hub facilities and managed the project, and in return Enterprise receives a monthly demand fee from the participants for the first five years and also receives a producing fee on the recovered reserves and a transport fee through the export pipeline.
The model ‘has evolved over a number of similar projects, not as a capital lease but as an investment opportunity wherein Enterprise actually participates in the resource risk,’ Guion says.
Enterprise worked with the producers to develop a budget for the project through participating in the FEED study. ‘It’s very transparent, the model we use,’ Guion says.
The size of the participants also helped, Guion says, noting that companies involved were fairly responsive in the decision-making department and were able to supply small project teams loaded with expertise to keep the project on schedule and on budget. ‘People were hand-picked for this job based on their expertise,’ Vardeman says.
The team-based approach to creating Independence Hub led to a rare thing, Guion says: ‘Successful management by a committee.’
A streamlined, decisive project team was crucial to contend with problems common in deepwater development: depth, platform motions, and temperature. ‘Many of the problems that were thought to prohibit development in this water depth (8000 ft) were addressed and managed during the project,’ Guion says.
ENGINEERING
Designing Independence
Alliance Engineering focused on managing change as it designed the Independence Hub topsides and then modified the plans to meet demands for more capacity.
In 2003, in response to an Enterprise request, Alliance started the conceptual study. The conceptual design started shortly thereafter. With project sanction in summer of 2004, engineering began in earnest. Detailed engineering was completed in fall 2005, and the producers decided the 850mmcf/d capacity wouldn’t be enough.
‘There were additional discoveries that were going to be tied back to the facility that gave them the confidence to spend the money to add to that expansion,’ Hickman Brown, Alliance Engineering’s senior project manager, says. ‘The biggest challenge that we had was that the facility was in the middle of construction.’
The expansion, Brown says, had always been in the cards. It just made sense to do it earlier rather than later, he says.
‘Any time you change direction, add capacity, add equipment, change line sizes, etc., while you’re in the middle of a construction project, it has to be managed very carefully or you will have a disaster in the making,’ Brown says.
Kent McAllister, Alliance Engineering’s project engineering manager, says constant communication with the client helped manage the changes.
‘We didn’t want to impact the original delivery schedule,’ McAllister says. ‘We had to jump through some hoops.’
Brown says many of the late changes revolved around additional equipment and getting the equipment purchased and delivered without affecting production times. This was especially tricky, he says, with long lead items like the compression package. The project benefited from vendor cooperation, Brown says, but ‘there were little pieces of this and that that caused us a bit of heartburn.’
Because of the capacity uprating, the hub’s entire Dresser-Rand sales compressor set had to be restaged. The facility, designed with five parallel compressors, suddenly needed a sixth. The expansion slot for the sixth compressor was filled earlier than originally planned. Each compressor has the capacity for export and the team added the sixth machine to increase the pressure on the export pipeline, Brown says.
Alliance called on Dresser-Rand to restage and fabricate an identical sixth compressor, Brown says. Because it was identical to the previous compressors, he says, the fabrication cycle was shorter. It was designed so it could be installed, worst-case scenario, offshore, but the team was able to install the modified compressor set at Kiewit Offshore Services at Ingleside, Texas.
McAllister called the compressor work the biggest impact on yard time. ‘To disassemble the compressor onsite in a dusty fabrication environment was something that just wasn’t planned for.’
Piping, valves, separation capacity, pump modifications, and chemical skid modifications proceeded while machinery was built, Brown says. ‘Because of the volume and pressures of the gas that we’re moving around, we have very large bore piping. We had to plan for the space required for this large heavy piping. We had to plan for the physical size of the valves and the weight of those valves. We went through a number of exercises to trim weight off the equipment and piping, including flanges.’
The topsides weighs in at 8250 tons dry and the total facility is 10,100 tons. The hub can accommodate up to 27 flowlines.
Mike Gann, Anadarko’s project construction engineering advisor for worldwide deepwater operations, says coordinated teamwork was vital for the schedule-driven project to unfold well, especially given the upsizing of the facility to 1bcf/d later in the game. ‘We incorporated that without any schedule delay but it did involve a lot of engineering,’ he says.
Jurong Shipyard in Singapore took a modular approach to fabricate the hull, Gann says. Equipment like mooring chain jacks and ballast pumps went to Jurong for inclusion in the facility. There was a slight delay in the delivery of the hull back to the US because of steel and people shortages, but the hub still came online ahead of schedule, Gann says.
‘There was a lot of competing work,’ he says. ‘Basically it all comes down to materials and people.’
The hull allowed quayside integration of the deck. The deck was put on the hull quayside and precommissioned, so that didn’t have to be done offshore, Gann says.
Supersize ME(G)
The Petroleum Experts’ Integrated Production Model (IPM) design, while giving the producers the confidence to develop the field with shared flowlines, did give one cautionary note: the originally planned monoethylene glycol (MEG) system wasn’t large enough. To answer that issue, Anadarko upsized the MEG system and injects the hydrate suppressant at every tree.
‘MEG is essential. If we don’t have MEG, we don’t flow,’ says Bob Buck, Anadarko’s senior staff production engineer for GoM deepwater operations.
In 8000ft of water, the ambient water temperature is about 38°F. On cold restarts, fluid temperatures downstream of the subsea choke will approach –33°F at 600psi topside pressure at the tree and are 8°F at 1900psi at the topsides.
‘It will freeze without MEG,’ Buck says.
Twelve of the 15 trees have subsea chemical infection valves (SkoFlo valves) that regulate MEG and chemical injection rates to the wells.
‘Using the SkoFlo valves has eliminated the need to run umibilicals to each tree,’ Buck says. One umbilical can serve a number of trees, which saves money.
At the planned rate of 1bcf/d, Buck estimates the lowest water production likely is 300b/d. The development plans center around an initial 1:1 ratio of MEG to produced water, Buck says, and the hub can hold a two-day supply of MEG.
‘We have to keep moving the MEG,’ Buck says.
The plans called for injecting hydrate suppressant MEG into the flowlines to be flowed back to the topsides facility with the produced gas and condensate, Brown says. From there, the MEG reclaimer, the largest known single train facility offshore, heats the combined water and MEG and draws off water and salts so the MEG can be reused.
This unit is designed for 7800b/d of MEG, which is 10 times the size of some of the existing facilities and 50% bigger than the largest one in the North Sea, Brown says.
Cameron’s Petreco division supplied the huge MEG reclaimer unit. ‘Petreco’s MEG reclaimer uses a proprietary vacuum flash process that utilizes the latest technology in order to maximize MEG recovery and to produce a clean waste salt stream which is suitable for overboard disposal,’ says Jim Keogh, sales director at Petreco.
The size of the unit made space an issue. ‘We had to design the unit into small interconnected skid packages to make maximum use of the limited space availability,’ Keogh says.
To minimize the weight of the MEG reclaiming equipment, the system was integrated into the topside piping, McAllister says. This allowed the large reclaimer to fit within the constraints of the facility and provided for flexibility in the layout of the system components. OE
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