Subsea separation gains momentum

The pazflor gas-liquid separation system is the first of its kind to be utilized on such an immense scale. Photo by FMC Technologies.

Greg App dives deep into the advantages of subsea separation units (SSUs), which have been deployed on fields such as Total's Pazflor development.

Nearly five years have passed since FMC Technologies introduced the world’s first large-scale subsea separation system. The Pazflor subsea gas-liquid separation system promised the ability to produce from subsea fields hindered by factors such as heavy oil, low productivity indices, and low gas-oil ratios. Historically, fields with these characteristics are not well suited for subsea production. Thus, this new implementation of subsea separation technology had the potential to change subsea development and processing outlooks throughout the industry.

Working under contract for Total E&P Angola since September of 2011, this next-generation subsea separation equipment seems to have met these high expectations. Positioned about 93mi. off Angola, FMC’s subsea separation units (SSU) have enabled the 238sq mi. Pazflor project to produce oil and gas from 25 subsea wells drilled in four separate reservoirs at water depthsto 4000ft.

The 2009 Offshore Technology Conference (OTC) paper “Comparison of Subsea Separation Systems” discusses the primary advantages of SSUs by high- lighting their ability to lift oil and water to the surface by utilizing gas-tolerantmhybrid pumps, a method found to be far more efficient than more traditional gas lift and multiphase pumping systems. Such technology is also cost effective. The omission of gas-lift systems and slug catchers results in extremely reduced compression size and more compact first stage separators. Additionally, and perhaps most importantly, subsea separation greatly reduces the overall length of the drilling trajectory (Fantoft, Gruehagen, Shaw, and Vu).

The introduction of this technol-ogy on a large scale has been successful, with Total calling the Pazflor SSUs provided by FMC Technologies a “bold innovation” and an “audacious solution.” According to Rob Perry, Director of Global Subsea Processing at FMC Technologies, “the success of subsea separation on Pazflor will endorse the fact that subsea separation is a reliable solution with technology that can be counted upon for significant levels of investment and associated revenue by the operators.”

Thus, as a single case study, the Pazflor project is a testament to the effectiveness of subsea separation technology in overcoming seabed production challenges. However, this is merely the first time to produce oil and gas from 25 subsea wells drilled in four separate reservoirs at water depths to 4000ft. Photos from FMC Technologies.

SSUs were utilized on such a large scale. According to the authors of a 2012 OTC paper, “Compact Separation Technologies and Their Applicability for Subsea Field Development in Deep Water,” subsea separation is attracting interest because of its ability to increase production, enhance recovery and improve field economics on a commercial scale (Akdim, Hannisdal, and Grave). The concept of this technology is not new; subsea separation and pumping systems have been in various developmental stages since the late1960s. In a 1969 OTC paper “Production Processing Prototype for Submerged Operational Test,” the authors explain that the world’s first prototype seafloor separation module was tested in 1969 offshore Abu Dhabi, and was successfully used for three years before being decommissioned. Another separation system was successfully tested in the Gulf of Mexico between 1972 and 1973 (Burris, Hill, and Lowd).

FMC's subsea separation units (SSUs) have enabled the 238sq mi. Pazflor project to produce oil and gas from 25 subsea wells drilled in four separate reservoirs at water depths to 4000ft. Photo by FMC Technologies.

However, despite these successful early prototypes, a lack of clear under- standing regarding the cost and benefits of this technology has prevented the industry from deploying it on any sort of significantly large scale until very recently. “The first subsea separation systems were conducted on an experimental level,” states Rune Mode Ramburg, Chief Engineer of Subsea Technology & Operations at Statoil ASA. “For the first few decades, there was not an immediate incentive to pursue this technology on such a large scale. However, as the need to drill in deeper waters became more apparent, so did the economic and logistical advantages of subsea separation.”

The industry’s interest in the potential advantages and opportunities provided by subsea processing and SSUs did not truly gain momentum until the implementation of the Norsk Hydro Troll C pilot in 2002. Based on ABB Offshore Technology’s Subsea Separation and Injection System, this pilot was able to remove and dispose of the water produced by Troll subsea well templates before piping the gas and oil as a mixed stream to the Troll “C” platform for continued processing. Three years after the successful installation and operation of the Troll subsea separation pilot, a study conducted by Douglas Westwood Energy Research Group indicated that industry enthusiasm towards this technology was on the rise. Although actual industry participation in the development of subsea processing was still relatively insignificant, the Douglas Westwood report revealed that 90% of operators expected to utilize this technology within 10 years.

These predictions began to materialize with the successful start-up of the world’s first full-field subsea separation system on the Statoil-operated Tordis field in 2007. Because of subsea processing advantages, operators in the Tordis field were able to increase recovery by 35MMbbl while extending the expected field life by almost 20 years.

Soon to follow was Shell’s Parque das Conchas project (BC-10) off Brazil, which has the distinction of hosting the world’s first subsea system with gas liquid separation and boosting. This system was developed with 13 subsea wells, six subsea separators and a floating production storage offloading system (FPSO). This project area includes five fields with an estimated 400MMbbl of heavy crude oil.

In 2011, the technological and economical advantages of subsea separation technology enabled Shell to make history with the Perdido project. Located in the Gulf of Mexico, the Perdido project has set multiple offshore industry world records, including recognition as the world’s deepest oil development and deepest drilling and production platform. Additionally, it is predicted to produce from the deepest subsea well on earth.

The Espirito Santo FPSO is a key component of Shell's Parque das Conchas(BC-10) project. Photo from Shell.

The Future

Kimball says that current technological developments will eventually lead to full subsea processing. “The technology developments in the area of subsea separation are related to ultra- deep separation solutions in addition to further treatment and separation steps that are required after the primary separation,” Kimball says. “FMC Technologies is already qualifying these methods, often through joint industry programs, which are undertaken in collaboration with operators that will deploy the technology.”

According to Ramburg, the technology to successfully implement a full-scale subsea processing system already exists,and its successful implementation is just beyond the horizon. “From Statoil’s point of view, the technology is definitely doable,” he says. “It is really just a question of economic incentive and necessity.

“Realistically, I believe that we will have installed a fully operational subsea processing system by 2020,” he says. “However, in the meantime, we are going to see multiple technological developments regarding subsea separation systems. These include secondary separation on the seafloor, improved efficiency of current separation systems and a larger utilization of subsea compression technology.”

Recent trends seem to indicate that industry confidence regarding the effectiveness of subsea separation technology is gaining considerable momentum. As the cost benefit analysis of SSUs becomes clearer with the increased participation of major operators, one can expect the remainder of the industry to follow suit in utilizing this technology to increase deepwater production.