Audubon Companies’ Denis Taylor and LLOG Exploration’s Craig Mullett discuss changing design considerations for condensate stabilization on the Delta House FPS in the Gulf of Mexico.
Delta House. Image from LLOG Exploration Co.
Coping with unexpected engineering challenges during the design and development of infrastructure is something that is inherent in the deepwater offshore oil and gas industry.
Case in point: LLOG Exploration’s Delta House floating production system (FPS) in the Gulf of Mexico (GoM).
Delta House, in Mississippi Canyon Block 254, was built under a rather unique set of circumstances. Unlike the conventional approach taken by most offshore operators, which involves delineating wells and studying reservoir composition before detailed design and construction begins, work on Delta House started before a discovery was even made. Part of this was due to the fact that the 20 or so deepwater leases acquired for production by LLOG in 2010 were set to expire in early 2014 – requiring expedition of the entire construction process so that the FPS could be brought online and wells could be drilled within 36 months.
In order to achieve this milestone and keep pace with the highly aggressive production schedule, topsides engineering contractor Audubon Engineering Solutions had to begin front-end engineering design (FEED) efforts before reservoir characteristics were defined.
Assuming a reservoir composition similar to a nearby analogous field (GOR of ~2000 scf/bbl and 28-32°API), the initial design included routing liquids from compressor scrubbers to production separators with lower operating pressures – a method commonly used on offshore facilities to reduce liquid recycle and minimize compression requirements.
During this initial design process, however, a well sample phase behavior (pressure, volume, temperature or PVT) analysis conducted by a third-party laboratory revealed that the reservoir contained a stock GOR of approximately 2300 scf/bbl and a crude oil gravity of 38°API – a substantial deviation from the previously assumed composition. The analysis also indicated that reservoir fluid was rich in condensates, including propane (C3), butane (C4), and pentane (C5), resulting in a much larger liquid recycle and higher compression requirements in order to meet oil pipeline Reid vapor pressure (RVP) specifications. Although Audubon Engineering Solutions and LLOG were suspicious whether this data was entirely accurate, given the unusual numbers, they proceeded under that assumption that if it were even remotely indicative of the reservoir’s composition, a conventional liquids handling philosophy would be impractical and other options would need to be explored.
Fig. 1: Simplified flow diagram of the condensate stabilization system.
Liquid handling options
When considering a new liquid handling design approach, two options were examined. The first option was to retain much of the equipment used in the original design and add a condensate processing train in order to dehydrate the condensate from the scrubbers before pumping it into the gas export pipeline. This approach would effectively eliminate the recycle loop and reduce compression requirements, but a lower volume of sales oil would be produced.
The second option included a complete overhaul of the original design by replacing much of the topsides equipment with a crude stabilizer. This would enhance separation of the condensates, reduce compression, and allow RVP specifications to be met. The process itself, however, was overly complex and required a great deal of heat in order to operate. The necessary equipment presented structural concern due to its weight as well.
During the process of evaluating these options, efforts were made to replicate the data from the initial PVT analysis in a process simulator. When it could not be done, a second analysis was ordered to confirm the suspicion that the data was incorrect. As expected, the second analysis revealed that the reservoir composition was in fact much closer to what was originally assumed (stock GOR and specific gravity were calculated to be ~2100 scf/bbl and 37°, respectively). This data was more favorable from a processing standpoint, but with relatively high amounts of condensate still detected, the large recycle loop remained.
After the new PVT data was verified in a process simulator, the total overhaul of topsides equipment and addition of a crude stabilizer was taken off the table. The option of adding a condensate processing train by itself was also reconsidered due to its inability to provide adequate separation. After examining different seasonal and environmental conditions in order to better understand how the facility would operate throughout the year, it was determined by LLOG and Audubon Engineering Solutions that a hybrid of these two options would be most appropriate given the unique composition of the field.
The solution: condensate stabilization
The new hybrid design for liquid handling at Delta House included keeping most of the equipment from the initial FEED phase – along with the condensate processing train – and adding a stabilizer with overhead cooling and two-phase separation of the overhead product. After receiving condensate from a freewater knockout and coalescing filters, bottoms product from the stabilizer would feed into the low-pressure separator. This design would ultimately improve compression capabilities and increase the volume of sales oil that could be recovered. A flow diagram of the condensate stabilization system used at Delta House is outlined in Figure 1.
Meeting seasonal RVP specifications
Due to the seasonal changes in oil pipeline RVP specifications, the stabilization system design had to be flexible enough to meet requirements under various operating conditions. In the winter (April to September), the system would have to meet an RVP specification of 9.6psi absolute (psia). During these months, a higher concentration of C3, C4, and C5 could be present in the sales oil and the temperature setpoint for the reboiler could be relatively low (250°F) – resulting in higher oil production rates and a lower volume of natural gas liquids (NGL). It was estimated that approximately 16.5 bbl of stabilized condensate would be produced per every 1000 bbl of crude oil.
In the summer months (April to September), a crude oil RVP specification of 8.6psia would have to be met. The stabilizer reboiler would operate at 315°F, which would allow for the maximum volume of stabilized condensate to be recombined with the crude before entering the sales line. In these conditions, the system would produce approximately 10 bbl of stabilized condensate per every 1000 bbl of crude oil.
Additional design considerations
Ambient temperatures also had to be considered when implementing the condensate stabilization system on Delta House. Outside temperature has a direct impact on aerial cooler outlet temperature, which in turn has an impact on the amount of condensate that feeds into the stabilizer, as well as the volume of NGL that’s produced. Although the aerial process coolers on Delta House were designed to operate with 120°F outlet temperatures, LLOG and Audubon Engineering Solutions had to ensure that this setpoint could be maintained in the colder months of the year. Figure 2 shows early life system operation parameters during the summer and winter months.
Because excessive volumes of water entering into the stabilizer could result in a number of costly issues, including the formation of a hydrate plug in the gas sales line, which can potentially force a total shutdown, freewater knockout and coalescence filters on Delta House were designed to remove as much water from the crude as possible. This was achieved by implementing a number of safeguards, including installing a water drain in the condensate stabilizer. Determining the presence of water was achieved by installing a sample location on the drain line, along with an interface level gauge and transmitter in the stabilizer overhead separator to alert operators in the event that water begins to accumulate.
Making Delta House a success
The Delta House FPS achieved first oil in April 2015 – roughly two and a half years after construction on it officially began and two full years earlier than similar platforms around the globe. It has a capacity of 80,000 b/d of oil and 5.7 MMcm/d (200 MMcf/d) of gas and hosts production from multiple fields.
The condensate stabilization system implemented by LLOG and Audubon Engineering Solutions on the FPS is just one example of the types of innovative methodologies that offshore producers are using to keep pace with the ever-present demand to optimize production facilities.
With relatively modest space and weight requirements (75-80 metric tons, 22ft x 24ft x 47ft), the use of similar equipment on offshore platforms could become more prevalent as operators look for cost-effective ways to improve yields and ensure that their product meets pipeline owner specifications – especially in fields where reservoir studies indicate higher levels of condensate.
Denis Taylor is a founder and managing partner at Audubon Companies. Taylor has over 25 years of engineering and project management experience in the oil and gas industry, including mechanical systems design and upstream and midstream consulting. His experience in the upstream industry includes the design and installation of floating deepwater facilities and production platforms in coastal Louisiana and on the Gulf of Mexico’s Outer Continental Shelf.
Craig Mullett serves as offshore construction manager for LLOG Exploration. Mullett has 35 years of experience in the engineering, construction, and commissioning of offshore oil and gas facilities.