Solving Deepwater Challenges in a Low Price Environment
Extracting maximum value is a tenet of the oil and gas industry. Whether it is a field located deep in the ocean or a rock formation located in the middle of a plain, companies are constantly searching for ways to get as much out of the resources available to them as possible with the tools they have.
In the search for untapped resources, exploration and production (E&P) companies are moving their offshore operations into extreme water depths, and with that shift comes an increasing litany of technical challenges unique to deepwater projects. With the price of oil at a low mark, these companies are looking for the most efficient and economical strategies to solve these challenges as they push into uncharted territories.
The 19th Annual Gulf of Mexico Deepwater Technical Symposium, held in New Orleans in August, featured several presentations on the challenges that operators face with deepwater projects in the current economic and technical environment. Speakers focused on a variety of issues, including construction costs, contractor involvement, flow assurance, and the integration of new technologies created to improve the production from their fields.
The Overall Landscape
During the plenary session, “Creating and Delivering Value in a Low Price Environment,” representatives from both small and large operators discussed their E&P philosophies and their strategies for adapting to the changing environment.
Marcia Houghton, general manager of US Gulf of Mexico (GOM) asset development at Chevron, emphasized the value that the company has derived from its partnerships in the region. Chevron co-owns the Caesar/Tonga project, site of the first lazy-wave riser system and the first 15,000-psi rigless stimulation system, with Shell and Anadarko. It also has an interest in Shell’s Perdido development, the world’s deepest subsea offshore drilling and production platform and site of the first full-field subsea separation and pumping system in the GOM.
Houghton said the high expense and uncertainty of deepwater projects forces companies to spread the risk assumed across multiple assets with multiple partners, and that the partnership requires an examination of a company’s drivers and assurance requirements.
“When things go wrong—and sometimes things do go wrong—we owe our partners an explanation as we develop it of what the root causes are in order to plan for future improvements. In turn, we hope that those partners will bring back to the table their experiences and best practices, and we have to listen to them when they speak,” Houghton said.
In addition, companies can reduce their exploration risk by focusing on their own strengths and recognizing their limitations. Rick Fowler, vice president of deepwater projects at LLOG, said a major element of his company’s success is that it concentrates its operations almost exclusively on the Mississippi Canyon formation in the GOM. The company operates floating production systems (FPS) in two fields, Who Dat and Delta House, in the area.
Fowler also said that as a private company, LLOG often focuses on developing projects with lower production thresholds, and it will seek developments near host facilities willing to accept third-party production.
“Some companies, especially majors, will have a minimum size that they take to be relevant to their business,” Fowler said. “Typically that’s over 100 million bbl. At LLOG, we do occasionally go for 100-million-bbl prospects, but oftentimes we’ll go after 20-million bbl if they’re in the right location and the economics support a 20-million-bbl development.”
Discretionary spending is also an increased priority in the current deepwater environment. Houghton said companies must spend more wisely and carefully than they have in the past, especially given the time frames that accompany investment decisions.
“The delivery of technology is often a long-range proposition, and the funding requirements for technology oftentimes are way earlier than when they’re going to be actualized on your facilities. Sometimes very significant commitments to accommodate space requirements on your facilities need to be made, even before you know if that technology is going to work out,” she said.
With limited financial resources, private companies must keep an even closer eye on discretionary spending in deepwater projects. To that end, LLOG saves money on projects by outsourcing infrastructure ownership. For Delta House, the company made a deal with ArcLight Capital, a private equity group, on its infrastructure entities. ArcLight agreed to provide 51% of the construction financing capital—an estimated USD 438.6 million—in exchange for a majority ownership interest in the FPS and oil and gas export pipelines. LLOG split the remainder of the financing with five other E&P companies (LLOG 2015).
Fowler said the ArcLight deal made a noticeable difference in the overall cost of Delta House, and it will continue looking for similar opportunities with deepwater projects.
“Being a private company, we certainly have limits on how much capital is available to us,” Fowler said.
For smaller companies, the development of and investment in new technology may not be the optimal route to follow. Fowler said his company seeks to be “the very first at coming second,” meaning that it often implements technology that has been proven by other companies.
Fowler mentioned his company’s partnership with FMC Technologies for subsea trees as an example. LLOG uses identical trees for its different deepwater projects, and Fowler said that the familiarity bred from this arrangement allows its workers to become well versed in that particular technology. It also makes it easier for workers to adapt to new projects without having to learn an entirely different system.
“When an operator is working on a problem on one field, if that operator gets moved to another field, he knows exactly what kind of tree he’s dealing with,” Fowler said. “He doesn’t have to learn three different systems. He doesn’t have to have five different contacts with five different companies to call.”
Chevron adopted what Houghton called a “program approach” for its activities in the GOM in which it identifies the specific needs within a project and works on each need concurrently. The teams coordinate their activities and the results are reported collectively so that the company can see the project’s development as a whole. Houghton said this approach helps the company find quick solutions to the problems that arise on deepwater projects.
“They’re big problems, and we need [solutions] soon because [solutions] are much less valuable if we don’t intersect them with our venture capital projects when the investments are made,” she said. Houghton said that the program approach ensures that all aspects of a problem are getting attention.
Fowler agreed that fast decision making is critical to a successful deepwater operation, particularly with regard to the construction work done at fabrication yards. When working on a project, LLOG typically has a representative at the fabrication yard with decision-making authority to handle problems that require immediate attention. He said that while other companies without a direct link to the fabrication yard may take between 2 and 3 weeks to respond to an inquiry, LLOG is able to make a decision in as little time as an hour.
LLOG’s close relationship with its contractors was a major factor in the success of Delta House. As they were involved in the project’s design from an early stage, the contractors were able to provide input that helped reduce the time needed to finish the topsides construction. Some of their suggestions included increasing the strength of steel used for the topsides from Grade 50 to Grade 60 and the adoption of a single truss spar design, which allowed for schedule gains in equipment deliveries (Chapa and Zoss 2015).
Jack/St. Malo: Technology, Execution
The Jack and St. Malo fields are among the largest in the GOM. Sitting in approximately 7,000-ft water depth in the Lower Tertiary trend, the fields have a production capacity of 170,000 BOPD and 42 million ft3/D of natural gas. The single-host, semisubmersible floating, production, storage, and offloading unit that connects the two fields is about as tall as a 30-story building and has a displacement of 160,000 tonnes.
For Chevron, the majority owner and operator of both fields, developing a project of this scale in ultradeepwater on time and within budget required strategic planning and creative thinking. In a presentation, “Jack/St. Malo: Ramping Up One of the Industry’s Newest Deepwater Developments,” at the symposium, Travis Flowers discussed the challenges Chevron faced during the project’s first development stage, when it increased production from the fields. Flowers is an asset manager at Chevron.
Jack/St. Malo delivered first oil in December, and Flowers said one of the biggest factors in reaching that point was the advance planning done in anticipating potential technical problems, particularly with export pumps, control valves, and safety valves. He said the project team had a plan in place to install secondary pumps and other alternate equipment if needed.
Also, the project team worked with regulatory agencies to determine what equipment could not be commissioned and factored the time it would take to deliver and install alternate equipment into the project schedule.
“The plan going into the startup was a great plan on paper, but how was it going to be in execution? In hindsight, I think it went extremely well, and a lot of that had to do with the planning,” Flowers said.
As Jack/St. Malo was a large-scale project in virgin territory, Chevron had to rely on several enabling technologies that it had not used much in its deepwater operations. One technology that Flowers mentioned was the subsea boosting system, which consists of three subsea pumps built to withstand 13,000 psi each. The pumps were installed in a 7,000-ft water depth and consume 3 MW of power, making them the largest pumps in the world by a considerable margin. The previous industry maximums were 5,000 psi pressure, 5,500 ft water depth, and 2.7 MW power consumption (Chevron 2015).
Chevron partnered with Statoil, a company with subsea boosting experience, to develop the pump system. Flowers said that given its size and Chevron’s unfamiliarity with the technology, the project team will monitor the subsea boosting system closely in the future.
“We’re very cautious of starting these pumps and shock-loading the formation, potentially causing a failure of the rock,” he said. “But, as the wells continue to deplete, it’s inevitable that these subsea pumps will be required to recover the ultimate reserves.”
Chevron has used subsea multiphase flowmeters on each well, topsides multiphase flowmeters on each flowline, and bulk separator meters on the export pipeline. Flowers said the company had “limited faith” in the multiphase flowmeters initially, but the data provided by each meter provided enough of a redundancy to allow for high-quality measurement accuracy in a short period of time.
“We had to have quality data from a fiscal perspective,” Flowers said. “We had to make sure our measurement was calibrated and our allocation was accurate. So far, we’re extremely pleased with having (flowmeters) topsides and subsea. They help us make real-time data analysis and decisions within a period of minutes to hours.”
The management team implemented parallel mitigation plans during the commissioning of the project to keep it on schedule. Flowers said the management team understood the project’s scope from the beginning, and the consistency of personnel from planning through execution helped the project stay close to its original scope.
“There was a very strong project management team here that very closely controlled the scope and made sure that the targets were on line and that everyone stayed on target with that scope,” Flowers said. “To me, that’s a lesson learned that I will take with me for the rest of my career. Managing scope is a huge opportunity to ensure that you deliver what you committed to.”
Shenzi: Flow Assurance
Flow assurance issues may complicate any offshore project, but for large, complex projects in ultradeepwater the potential impact of these issues is even more significant. The operators of these projects are devising strategies to help mitigate them.
In their presentation, “BHP Billiton Shenzi Production Optimization,” representatives from BHP Billiton discussed the steps the company took to enhance flow capacity within the Shenzi field, which is located in the Green Canyon, approximately 120 miles from the Louisiana coast. Co-owned by BHP Billiton, Hess, and Repsol, and operated by BHP Billiton, the field sits in 4,300-ft water depth and drew first oil in March 2009.
To operate the field, BHP Billiton developed an initiative called “capacity enhancement,” in which its surface engineering, subsurface engineering, facilities, field, and operations teams look for ways to increase flow capacity within its production system. The process involves the input of real-time data from downhole gauges, flowlines, and topsides into nodal analysis models, which help estimate production rates.
The production team then analyzes the results of each model and determines the components of the system that are limiting flow capacity. The operations team determines the cost of improving the performance of a given component. Derek Cooper, a production engineer at BHP Billiton, said the management team must decide the direction to take.
“We are able to prioritize opportunities and basically grab the lowest-hanging fruit first,” Cooper said. “After we prioritize, we plan our jobs, do our risk assessments, follow all of our normal processes, and complete our jobs.”
Cooper said one of the more challenging areas is the management of asphaltene deposition. A typical well at Shenzi has 5½-in. tubing, an upper chemical injection mandrel (CIM) located approximately 8,000 ft below sea level, and a lower CIM located just below the downhole gauges. Cooper said that the asphaltene onset pressure (AOP) in the tubing typically ranges from 2,000 psi to 4,000 psi.
By knowing the range of AOPs, the project team can use one of two techniques to mitigate asphaltene deposition. The first strategy involves the continuous application of inhibitor fluid against the lower CIM prior to the point at which asphaltenes are known to break out in the solution. If the inhibitor does not effectively reduce the deposition, the team then shuts in the well and pumps approximately 5,000 gal of xylene into the upper CIM. Cooper said that while this is a more robust method, it presents its own problems.
“That well’s going to be shut in for 4 to 6 days, and when you’re talking about 10,000 BOPD on some of these asphaltene wells, your production deferrals are going to be quite high,” he said.
The project team has multiple ways to determine its inhibitor strategy. One is by building an integrated field model that restricts the tubing inner diameter (ID) and matching that model with the deposition trend in real time. Another method is to run a diagnostic test that compares the vertical lift performance of the rig with the vertical lift performance of the downhole pump. Cooper said this test shows the carrying capacity of fluid in a pipe at a given downhole pressure.
Using the models to trend various rates over time, the project team gains a better sense of asphaltene deposition in a given pipeline. The models are also used to justify inhibitor strategy, whether it involves a change in inhibitor concentration or a switch to xylene soaks.
An example Cooper referenced was with Well H, the most aggressive asphaltene well in the Shenzi field. He said the project team noticed significant deposition in the well, and the problem grew so severe that it eventually had to bridge the well off. The team tried two xylene soaks to remediate the problem without much success. On the third soak, it brought the well on line with an inhibitor concentration of 1,500 ppm. Cooper said that this was the optimal operating point for the well, as the effective tubing ID reduction from asphaltene deposition decreased from 45% to 30%.
For Further Reading
OTC 25897 SS Delta House—Topsides Fabrication & Integration by J. Chapa and K. Zoss, Kiewit Offshore Services.
Chevron. 2015. Tapping the Unreachable at Jack/St. Malo, http://www.chevron.com/news/inthenews/article/08072015_tappingtheunreachableatjackstmalo.news (accessed 3 September 2015).
LLOG. 2012. Delta House: A New Hub in Mississippi Canyon, http://www.llog.com/images/pdfs/2015-01_delta_house_pub.pdf (accessed 27 August 2015).
Equinor Starts Up Mariner Field in North Sea
One of the largest industrial projects in the UK in recent years, Mariner marks Equinor’s first operated field on the UK Continental Shelf. It is expected to produce 70,000 BOPD at peak rates.
Equinor Gets Green Light To Start Up Utgard
The Norwegian Petroleum Directorate has given clearance to start up facilities at the North Sea field, which straddles the line between the UK and Norwegian sectors. Production is set to begin in September.
ALE Completes Record Lift for Total’s Egina FPSO
At nearly 3,000 tonnes, the company said its lift of an FPSO module was one of the heaviest land-based crane lifts ever performed. ALE was contracted to lift six modules for Total’s FPSO module integration project in Nigeria.
Don't miss out on the latest technology delivered to your email every two weeks. Sign up for the OGF newsletter. If you are not logged in, you will receive a confirmation email that you will need to click on to confirm you want to receive the newsletter.
06 August 2019
06 August 2019
08 August 2019
16 August 2019
05 August 2019