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Back to the drawing board at Mad Dog 2

Focusing on value over volume helped BP and its Mad Dog 2 partners devise a production plan that is economic in a low oil price environment

BP discovered Mad Dog in 1998 and began producing the deep-water Gulf of Mexico field with a spar in 2005. Current estimates of oil in place are 5 billion barrels.

“It’s a world-class field by any kind of measure,” says Bill Steel, Mad Dog 2 project general manager. “Overall, Mad Dog is a good news story. The more we drilled the field, the more we appraised the reservoir, the more oil we found.”

The Mad Dog spar has the capacity to produce up to 80,000 gross barrels of oil and 60 million gross cubic feet of natural gas per day. The field covers Green Canyon blocks 825, 826 and 782.

Given the additional oil BP found, the supermajor decided another facility was necessary to properly produce those reserves.

“That led us to looking at a second phase of development,” Steel says.

BP Bill Steel, Mad Dog 2 project general manager.  Photo: BP
 

BP dubbed the initial concept for the Mad Dog 2 host facility, a nearly 50,000-ton spar, Big Dog. It was to serve up to 33 subsea wells and produce up to 130,000 barrels per day of oil and 75 million cubic feet per day of gas handling, with first oil targeted for 2018.

Fourteen of the wells were to be water injectors serving a 280,000 barrel-per-day waterflood programme. However, in 2013, BP and its partners scrapped the plan as being uneconomic and went back to the drawing board.

The operator reshaped its development philosophy around value over volume, industry-led solutions, and co-owner collaboration, says Steel, who joined the Mad Dog 2 team about the time the development plans were recycled.

“You can characterise Big Dog as going all in, chasing every barrel,” Steel says. With the new plans, “we’re not going to chase every barrel from day one. We’re focusing on value here. At the recycle, we planned to produce about 90% of the resource for two-thirds of the cost” of the original Big Dog development price tag.

BP Initially, the Mad Dog 2 semi-submersible will accommodate up to 14 production wells and eight water injection wells.  Photo: BP
 

With planning and a mix of technologies, Steel says, the operator believes it can produce 100% of the Mad Dog 2 resource at less than 50% of the original Big Dog cost estimate. Target first oil is late 2021.

During a July 2015 earnings call, BP chief executive Bob Dudley said the Big Dog project would have cost as much as $22 billion, while the recycled Mad Dog 2 development costs are estimated at around $9 billion.

BP sanctioned the phase two development plan in December 2016, with partners BHP Billiton and Union Oil Company of California, a Chevron US affiliate, signing off on the project in February 2017.

BP holds 60.5% working interest and operates the project. BHP Billiton holds 23.9% interest and Chevron holds 15.6% interest in the project.

“We’re looking at four years from (final investment decision) to first oil,” Steel says.

BP says Mad Dog 2, which will see a production semi-submersible moored in 4500 feet of water six miles (9.5 kilometres) south-west of the existing Mad Dog spar in Green Canyon Block 782, is economic at $40 per barrel oil prices. With Big Dog, BP was looking at a project that was barely economic at $100 oil.

“We had a big challenge after the recycle. Some thought that deep water was finished, but you can see, deep-water projects can still be economic in the price environment we’re in if they’re designed in the right way,” Steel says.

That requires “the right working relationships, and the right level of trust where you can have an exchange of technical information” and draw on co-owner strengths.

For example, he says, BHP brought a strong water injection system design and operating lessons to the table, while Chevron brought design and fabrication experience from their recent Gulf of Mexico projects.

BP Wells drilled for Mad Dog 2 will be in water depths of 4500 to 7000 feet, as the field straddles the Sigsby Escarpment.  Photo: BP
 

Steel says the project team focused on simplifying and optimising systems and equipment.

“We worked with contractors and vendors. They know their businesses, and they have great ideas. We want to make sure the standards we put in place are fit for purpose and don’t compromise safety,” Steel says.

“We took a hard look at our requirements and challenged ourselves to adopt the industry standards. We implemented a lot of what contractors and vendors told us.”

One example Steel cites is adopting OneSubsea’s standard Fastrac subsea production tree. Additionally, the team optimised the power generation, which allowed the project to adopt a field-proven GE engine standard across BP’s Gulf of Mexico facilities.

“As a result of vendor challenge on the oil metering package, we gave a minor relaxation in clearance at four locations, which simplified the skid from two decks to a single level, resulting in a safer, more operations and maintenance-friendly design with a 50% weight saving,” Steel adds.

Mad Dog 2 would not be quite as viable without four key technologies — seismic imaging and processing along with an ocean bottom node survey for understanding the reservoir, immobile proppants to maintain the sand pack in injection wells, LoSal to boost recovery rates, and lazy wave risers to decouple the motion of the risers from the vessel and improve the fatigue life of the risers.

 

Seeing below the salt

BP has invested heavily in seismic acquisition, interpretation and processing. A key goal, according to Ahmed Hashmi, BP’s head of upstream technology, is to improve imaging below salt bodies, which are prevalent in the Gulf of Mexico.

Later this year, BP will carry out the largest to date deep-water ocean bottom node (OBN) survey on the Mad Dog field.

“That is something we are eagerly looking forward to in the Gulf of Mexico,” Hashmi says. “This will be used to further our knowledge of the field, identify drilling locations and de-risk the locations we’ve already identified.”

BP will place 2600 recorders separated by 400 metres on the ocean bottom at a depth of 1500 metres. They will cover an area of over 335 square kilometres, and BP will conduct the survey over an area of 1553 square miles (4022 square kilometres), sending about 600,000 source pulses into the subsurface. The entire operation will take several months to complete.

BP The Mad Dog 2 semi-submersible will be a similar size and design to the Atlantis facility, also in the Green Canyon portion of the deep-water Gulf of Mexico.  Photo: BP
 

“You can get a sense of the long offset we are seeking here. It improves the illumination of the reservoir and improves the signal-to-noise of the image that is created in our Center for High-Performance Computing (CHPC).

"We’ll be getting a lot of richness in the wave-field,” Hashmi says. “We’ll see the soundwaves across a wide range of angles.”

Each angle provides slightly different detail, and the operator’s CHPC in Houston, opened in 2013 (Upstream Technology 02/2013), will devote petaflops of processing power to help BP “deconstruct the salt and see through it”, Hashmi says. “This gives you the ability to understand the salt and then look below it.”

This is crucial not only for the salt present in the Gulf of Mexico but the complex faulting system. The longer offsets provide more richness in the seismic imagery, which makes it possible to better identify the faults. An added benefit, he says, is that this also can reduce the problems encountered with drilling too close to a fault because wellbore trajectory can be more precise.

BP Initially, the Mad Dog 2 semi-submersible will accommodate up to 14 production wells and eight water injection wells.  Photo: BP
 

 

OBN surveying provides large data volumes, requiring vast computational power, such as that in BP’s CHPC. Digital technology has sped up the processing times substantially.

“There are now common platforms where people from different sub-disciplines are looking at the same data. When one makes a change here, everything changes,” Hashmi says. “We’re almost in real time. That’s our vision.”

BP has shortened the amount of time it takes to carry out an OBN survey by using its ISS technology.

“We are looking at making it more efficiently, making it faster and easier to handle,” Hashmi says.

 

Controlling sand issues

Injection wells can lose gravel packs during water injection, so sand control can be compromised when they are shut in and subsequently restarted. BP wanted to find a sand control solution that water injection wouldn’t wash away.

“Nothing in the market addressed this when we looked at Mad Dog 2,” Hashmi says.

The company worked with suppliers in and out of the industry seeking a solution, which led to testing of a novel resin coating technology in 2013 and 2014.

BP Ahmed Hashmi, BP’s head of upstream technology.  Photo: BP
The result of development was a proppant that does not move yet allows water to pass through. It does not slow water going into the formation but does prevent sand coming into the wellbore, Hashmi says.

“We had to create our own testing protocol because this was quite novel. We identified bespoke testing procedures and we worked with test facilities around Houston in 2013 and 2014,” he says.

“We have now developed a new proppant that has proven in our tests to be the most robust.”

The immobile proppant, called Fusion and designed by CARBO Ceramics, has been used in onshore field trials in the US and in two wells in the Gulf of Mexico.

“Given the success of the immobile proppant so far, we can see using this in other places in the world and the Gulf of Mexico,” Hashmi says. “This is a significant improvement that can lead to changes in the way the industry completes injection wells.”

 

Enhancing recovery

LoSal EOR, which BP is deploying at its Clair Ridge field in the UK North Sea, will significantly improve recovery. “We’re bringing this to the US for the first time as an industry,” Hashmi says.

BP developed the low-salinity water technology (Upstream Technology 01/2013) over the course of nearly two decades, after a research programme in the 1990s indicated injection of water with lower salinity levels led to “a significant and meaningful recovery factor over the life of the field”, he says.

Extensive laboratory testing was followed up with field tests around wells and in between wells, which allowed BP to prove low salinity performance and understand the physical mechanism. The company says the LoSal technology will increase recovery at Clair Ridge, scheduled for start-up in 2018, by an additional 42 million barrels.

For Mad Dog 2, the LoSal fluid has been “tuned” to subsurface conditions, Hashmi says.

BP The Mad Dog 2 semi-submersible will be moored in about 4500 feet water depth.  Photo: BP
 

“We can tune the salinity we inject in the water for the rock and the clay content of the rock,” he says. “It’s a complete solution based on understanding the mechanism of LoSal enhanced oil recovery.”

At Mad Dog 2, the plan is to inject a minimum of 140,000 bpd of LoSal water when the field goes on stream with an option to increase the water injection rate to 210,000 bpd as the field matures.

Using low-salinity water for injection offers benefits beyond improved production.

“We don’t use LoSal simply to get barrels. We also use it to reduce the possibility of scaling later as the reservoir matures,” he says. “We’re lowering the risk of souring and scaling, and the benefits come at low incremental cost” of $3 to $5 per barrel.

“We feel pretty good about the subsurface because it’s an extension of the existing Mad Dog field,” Steel says. “We have produced close to 200 million barrels from Mad Dog.”

BP The truss spar serving the Mad Dog field went on stream in 2005. The Mad Dog 2 semi will be six miles south west of the spar.  Photo: BP
 

Phase two calls for up to 14 production wells and eight water injection wells. As of the end of the first quarter of 2017, BP had drilled two production wells and one water injection well as part of phase two.

“We found pressure connectivity to the wells on the spar, so that helps us better understand how the reservoir is plumbed up. In this case, Mad Dog 2 is less risky than a typical new deepwater development.”

BP plans to have two MODUs drilling in the field beginning early 2018 with continuous drilling up to targeted first oil in late 2021. “We want the facility full at first oil,” Steel says.

Wells drilled for Mad Dog 2 will be in water depths of 4500 to 7000 feet, as the field straddles the Sigsby Escarpment. Most will be drilled in the shallower waters, although at least one water injector will be in deeper water.

Production scheme

The Mad Dog 2 development concept calls for a semi-submsersible, and it uses Atlantis, also in the Green Canyon portion of the deep-water Gulf of Mexico, as an analog.

“We’ve had a great operating history with Atlantis for over 10 years,” Steel says. “Mad Dog 2 is a similarly-sized semi-submersible, and the same basic design as Atlantis. The semi-submersible is very flexible in terms of adding future capability if and when we need it.”

There may be “infill drilling as we get dynamic data from the reservoir. Maybe we’ll need more wells, maybe we’ll need less,” Steel says. The leases to the south-west involve the same co-owners as Mad Dog, he notes, so there is potential for additional subsea tie-backs into the existing subsea system.

Of the 75 MMcfd of gas that Mad Dog will produce, about two thirds will be used for riser-based gas lift, while the balance will either be used for fuel or exported.

BP awarded Samsung Heavy Industries a $1.27 billion contract to fabricate the Mad Dog 2 platform, which will weigh an estimated 58,000 tons. Wood Group is handling topsides engineering, while the hull is a design from KBR’s GVA division.

Subsea 7 will handle engineering, procurement, construction and installation of the subsea umbilicals, risers and flowlines and associated subsea architecture.

Mad Dog 2 project moves into detailed engineering

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Mad Dog 2 is the first substantial project in the US to use Subsea 7’s Swagelining polymer lining technology.

Schlumberger company OneSubsea won an engineering, procurement and construction contract to supply the subsea production system. The scope includes subsea manifolds, trees, control system, single and multi-phase meters, water analysis sensors, intervention tooling and test equipment for producer and water injection wells.

The Subsea 7 and OneSubsea collaboration Subsea Integration Alliance was awarded an engineering, procurement, construction and installation contract for subsea controls, flexible risers, pipeline systems, umbilicals and associated subsea architecture.

Steel says the overarching challenge of the Mad Dog 2 project has been delivering on the business objectives in a tough price environment.

“Two-thirds of industrial mega-projects fail to deliver on their business objectives,” he says. “BP is developing a better track record. We have a first quartile performance with regard to our peer group. We aim to deliver that with Mad Dog 2, too.”