High-cost subsea sector faces test of economics

Companies look to integration, standardization to cut cost of subsea completion/production technologies

By Katie Mazerov, Contributing Editor

Risk, cost and safety and environmental concerns impact every aspect of oil and gas recovery, but these challenges are especially daunting in the subsea sector. Here, as operators drive into increasingly deeper reservoirs and high-pressure, high-temperature (HPHT) fields, a single failure can be catastrophic. Innovation in this high-profile area has focused on reliability, with completion systems that can perform safely and efficiently for the long term, and the development of architecture for the seabed.

In recent years, however, the biggest obstacle in subsea completions has centered on cost, especially in deepwater and ultra-deepwater fields. “Operator returns on deepwater development investments have been eroding for the last couple years, with rig rates, the cost of subsea gear, pipelines, steel and other materials mushrooming while oil prices remained stagnant,” said Brad Beitler, VP Technology for FMC Technologies. The drop in oil prices that began a year ago put further pressure on the already-tight market but also presented a pivotal opportunity for the industry to take stock and come up with a better way to develop subsea fields.

The result has been a collaborative push for greater integration of services, processes and hardware, and standardization of equipment – all aimed at engineering the costs out of subsea completions while maintaining safety and reliability to ensure wellbore integrity. “Crises provide an opportunity to re-evaluate what we, as services providers, should be doing and understand what drives our customers’ economics. The environment we are in currently is a test of economics,” Mr Beitler said. He added that West Africa, the Gulf of Mexico (GOM), Brazil and the Norwegian North Sea are subsea markets seeing the most activity, with East Africa emerging.

The trend toward integration in the subsea sector is occurring across the board, from the design and standardization of subsea trees and control systems to eliminating hardware interfaces to the inspection and monitoring of subsea facilities. In Brazil’s massive pre-salt reservoirs, Petrobras has implemented standardized subsea trees and control systems, which was addressed in a paper, “Subsea Solutions in the Pre-Salt Development Projects,” presented by Senior Petroleum Engineer Paulo Cezar at this year’s OTC in Houston.

In the Santos Basin, a single subsea tree design was adopted for four different applications, including production wells, water-injection and gas-injection wells, and water alternating gas wells. The paper describes the standardized configuration being enabled by an electro-hydraulic, multiplexed control system, with the trees featuring standard mechanical interfaces that allow the main modules to be interchanged for operational flexibility.

The tree assembly includes an 18 ¾-in. production adapter base, which has a drill-through capacity of 16 ¾ in. that saves rig time by reducing the number of BOP runs. Both the production adapter base and the subsea tree can be installed by a drill pipe riser, a drilling or workover rig or by cable using a subsea equipment support vessel. The system is also compatible with intelligent completions of up to three zones for production and injection wells.

Integration for ultra-deepwater

OTC was the platform for Baker Hughes to introduce its integrated wellhead-to-reservoir ultra-deepwater completion and production system, engineered for well depths up to 33,000 ft and water depths up to 10,000 ft, as well as temperatures and pressures as high as 300°F and 25,000 psi. The Hammerhead system, which will begin field trials later this year, was designed to enable reliable long-term, high-rate production. It received the 2015 Innovation Award from the American Society of Mechanical Engineers at OTC.

Design of the system was initiated in 2012 in response to operators’ need to overcome technology gaps for developing the GOM’s ultra-deepwater Lower Tertiary trend, explained Robbie Pateder, Director, Lower Tertiary Integrated Product Team (IPT) for Baker Hughes. The multidisciplinary team was tasked to deliver a portfolio of products, including upper and lower completion systems, an isolation assembly and intelligent production capabilities.

“The Lower Tertiary holds tremendous resources and opportunities, yet there has been a lack of available technology from a completion and production standpoint to get projects off the ground and make them viable,” Mr Pateder said. “Ultra-deepwater development costs are staggering, especially when there is no infrastructure in place. The Lower Tertiary’s very tight, low-permeability formations necessitate unprecedented stimulation requirements in terms of the amount of proppant we can pump and the pumping rates required to unlock hydrocarbons.”

The IPT took a holistic approach in designing a comprehensive system to make subsea wells economical in terms of equipment deployment, stimulation, monitoring and zonal control to shut down problem zones and address scale buildup and other issues over a 20-plus-year lifecycle. The system was designed in three years, about half the time for a typical “step-change” technology to come to market, he noted. “We engaged operators in the process to shorten the development cycle and built the system with heightened safety and reliability.

“Typically, operators use multiple suppliers for completion systems, often cobbling together components such as packers and flow control valves, and performing due diligence regarding specifications and compliance,” Mr Pateder continued. “By providing an integrated system that encompasses all phases of subsea completion and production, with all the components designed to the same standard, we are simplifying the process and lowering costs for operators.”

Designed for compatibility in large cased-hole well scenarios with 8 ½-in. drift casing sizes to enable 30,000 bbl/day (BPD) production, the system is rated to 25,000-psi bottomhole pressure to meet the requirements for ultra-deepwater plays, he noted. “The single-trip, multizone lower completion has an inner diameter (ID) of 5 ¼ in., the industry’s largest, allowing operators to install a large work string to stimulate a well to unprecedented levels for unlocking hydrocarbons. Aggressive stimulation coupled with large production tubing facilitates 30,000 BPD flow capacity and enables economic use of artificial lift to extend production at high rates.”

Production is further optimized with remote surveillance and control capabilities, and proactive flow assurance enables sustained production rates. “The system is rated for 15,000-psi pressure differential from zone to zone, enabling the capability to improve recovery rates by reducing abandonment pressure,” Mr Pateder added. “Dual-zone flow control also enables enhanced recovery by providing the ability to choke down a zone while maintaining production from other zones.”

Once the system has been accepted in the Lower Tertiary, it will be adapted for the conditions of other frontiers. Through its alliance with Aker Solutions, Baker Hughes plans to develop a next-generation system for higher differential pressures, incorporating the Baker Hughes in-well electrical submersible pump technologies and advanced subsea boosting capabilities.

Rigorous qualification

When it comes to subsea safety systems, reliability is a key focus and must be maintained with increased functionality, such as delivering faster response times or increasing cutting capability, said Colin Mackenzie, VP Subsea for Expro. “Operators are looking for service providers to demonstrate reliable products and services across a range of potential conditions, including deepwater, HPHT and high-debris wells, which has led to rigorous qualification of existing and new products.”

Recent innovations include new-generation subsea Christmas trees, with operators considering the total installed cost, he noted. “This leads to designs that facilitate the use of in-riser subsea test assemblies (SSTA) for safe and efficient subsea well commissioning.”

Earlier this year, Expro launched its latest-generation SSTA for exploration applications. It provides a fast response system for use in deepwater reservoirs, with valve closure occurring in less than 10 seconds. It is equipped with a multilayered redundancy control system with full data-acquisition capability, Mr Mackenzie noted. The system completed core qualification in March 2014 and high-temperature qualification last November and has now been contracted by several clients.

The product is the first of Expro’s SSTAs to be qualified at the company’s new Research, Development and Qualification facility in Aberdeen, completed in September 2014. The facility is designed with dedicated test bays for each of the main qualification tests, including cutting, temperature, pressure, debris/slurry and gas, and controls simulator to test and qualify software and electronics.

Expro is also developing a next-generation landing string (NGLS), a subsea completion SSTA aimed at enhancing functionality and product lifecycle management. “We believe this development will see an industry shift from open-water systems to in-riser systems for subsea well completion and intervention operations,” he said. Qualification of the NGLS will commence this summer, with commercialization expected in 2016.

A major challenge in the subsea sector has been a lack of standards specific to SSTAs, leading to reliance on different interpretations of what constitutes an industry-qualified SSTA, Mr Mackenzie continued. To that end, Expro is participating in an API committee working on better defining design, qualification and operating standards. “The new standard will be released by the end of the year and should unify and clarify the application of existing standards, giving operators further confidence in the use of SSTAs for subsea well commissioning and intervention,” he said.

Focus on integrity

Also launched at OTC was Underwater Integrity Solutions (UIS), a company focused on integrity, production assurance and life extension of subsea facilities. “There is no single company in the market today that is global, independent and solely dedicated to subsea integrity,” UIS CEO Bill Boyle said. “Outside of boat owners and operators, the supply chain is extremely fragmented, with a variety of companies providing expertise for specific individual assets, such as risers, moorings, pipelines, cables, manifolds or trees.

“Then there are the providers of engineering solutions such as risk-based inspection, reliability engineering, flow and production assurance and data management. Lastly, there are the providers of smart products associated with inspection and/or repair,” he continued. “Often, these are small- and medium-sized companies with a limited geographic focus or client reach, but the solutions are fantastic and could bring significant improvements if deployed globally or bundled into a more focused product offering for a particular field.”

UIS is being launched at a time when operations continue to go into deeper waters and more hostile environments, Mr Boyle said, noting there are an estimated 5,000 operational subsea well globally. Nearly 7,000  more are forecast by 2020, he said. “As the industry continues to put more complex production facilities on the seabed, there is a need for a different approach to subsea integrity if we are to reduce costs, extend field life and operate safely.”

Mr Boyle also noted that the average subsea field age is between 15 to 20 years, with a significant number of fields experiencing issues related to design life expiration, equipment fatigue, flow assurance, changes in production chemistry,  condition monitoring, repairs, data management and analysis, and even change of ownership. “All these give rise to a need for a more integrated approach to integrity.”

UIS is investing $150 million of equity to acquire companies in the integrity management supply chain and will partner with other companies as it aims to become a portal for global expertise in subsea integrity. The company plans to close three strategically important acquisitions before the end of the year.

“Industry feedback indicates that operators are ready for an independent integrity service that will enable them to challenge the cost of operation and, in some cases, extend field life while continuing to operate safely,” Mr Boyle said. “Getting more value from existing subsea assets is what integrity is all about. The subsea arena is relatively new, but if we look to the onshore and offshore topside sectors, over time, several global independent integrity players have emerged. We believe the subsea sector has evolved to the point where a global independent subsea integrity company also is needed.”

JIP collaboration

Alongside integration in subsea production is a trend toward collaboration. In May, FMC Technologies and French engineering and construction firm Technip established Forsys Subsea, a 50/50 joint venture to conduct front-end engineering design (FEED) studies with concept selection teams at oil companies to reduce costs and redefine the way subsea fields are designed. “By integrating the process of equipment installation on the seabed between the surface contractors and the subsea production contractors, we can eliminate a lot of the interface hardware and make the entire operation more efficient,” FMC Technologies’ Mr Beitler said.

For example, use of a single electrically heated flow line eliminates the need to install a second flow line to circulate hot fluids to remove hydrates. FMC Technologies is also fabricating manifolds and other structures that weigh less, leave a smaller footprint and can be installed by smaller, lower-cost vessels.

HPHT fields are the focus of the biggest technology push, Mr Beitler said. Last year, FMC Technologies established a joint development agreement (JDA) with four major operators with considerable GOM assets – Anadarko Petroleum, BP, ConocoPhillips and Shell – to develop subsea equipment and systems for deepwater reservoirs with pressures of up to 20,000 psi and temperatures of 350°F. The company is also designing a class of equipment rated for 15,000 psi and 400°F.

“A key objective of the JDA is to design a common system that uses the same specifications for materials, inspection, testing and procedures,” he said. FMC Technologies selected DNV GL to deliver independent, third-party verification of HPHT completion and production systems for the JIP. “Using one company to provide verification services that in the past were contracted separately by each operator results in further cost savings.”

Subsea boosting for enhanced oil recovery in fields with installed infrastructures is also a priority. Some resource-rich fields in West Africa, for example, experience pressure drops early in well lifecycles and require boosting to keep production levels high, he added.

“On the horizon are remote power-generation for pumps, increased monitoring of subsea equipment for the life of the field and advances that will enable remotely operated underwater vehicles (ROVs) to be more efficient and autonomous in both the production and drilling environments,” Mr Beitler said. “These developments could eventually impact BOPs and rig support operations, providing more safety and efficiency to the drillers and field operations.”

Defining technology gaps

Defining where technology gaps exist is one of the objectives of the Ocean Energy Safety Institute (OESI), established in 2013 by the US Bureau of Safety and Environmental Enforcement (BSEE). RPSEA (Research Partnership to Secure Energy for America) is part of the OESI consortium that received $5 million from BSEE to develop a program to help safely guide the industry into frontiers. “We’re developing a repository of ongoing research and development activities that ultimately will be turned over to the industry to determine how best to move forward,” James Pappas, RPSEA President, said. The repository will include R&D work related to safety and the environment. “Industry is leading the charge and coming together to continue making safety a top priority and tackling issues through SEMS (Safety and Environmental Management) programs.”

Under a program funded by the US Department of Energy and managed by the National Energy Technology Laboratory, RPSEA provides financial incentives for subsea drilling and completions research projects that include annular pressure buildup mitigation, a super-shearing device, mudline kick detector and smart drilling fluids and casing. The University of Houston is developing a method for recording cement contamination on the fly downhole so the cement can be circulated out before it sets. The project is due to be completed this year, with the next step being industry field trials.

A BOP ram sensor, being developed at the GE Oil and Gas Global Research facility in Niskayuna, N.Y., will move into the FEED and prototype development phase this year. “GE eventually wants to combine the actuation system with a smart BOP, initially to keep a running record of how the BOP components are performing in order to better predict failure,” Mr Pappas said. “The ultimate goal is to develop a database for the entire BOP system to improve failure rates on the rams themselves and facilitate an automated process of predictive maintenance. Currently, predictive maintenance is done manually or is automated on a limited component basis.”

Embracing multilateral completions

In their push for greater efficiency and reduced costs, some subsea operators are embracing what has for 20 years been a niche methodology – multilateral completions.

“The high-cost subsea environment lends itself to multilateral technology because it is a very cost-effective means of maximizing a well’s reservoir exposure. Operators want to ensure their investment is safe and that risks are properly managed. Therefore, a technology must demonstrate high reliability,” said Ben Butler, FlexRite product manager for Halliburton’s Sperry Drilling business line. Over the last 15 years, the company has enhanced the technology, which today has a success rate of more than 99%, he said. In 2012, the company introduced the FlexRite MIC (Multibranch Inflow Control) system, which creates an isolated junction and allows an intelligent completion to pass through it, providing the ability to flow-control and monitor multiple laterals individually.

“There has been a clear shift in the industry toward adopting multilateral completions for both new and mature fields,” Mr Butler said. “We attribute this trend to customers being more comfortable with the approach and happy with the reliability and cost savings it brings versus drilling an additional well from scratch. The technology has evolved from a simple commingled isolated junction, with two legs flowing into the same wellbore, to being able to control multiple separate laterals with the same completion, in much deeper wells. A dual-lateral subsea well typically provides the exposure of two wells for the price of about 1.6 single wells. As we add more laterals to the well, we’re further reducing the incremental cost of each new lateral when compared to multiple single wells.”

On Australia’s North West Shelf, Halliburton is deploying the system on mature fields to help operators tie back new laterals to existing wells and open up new sections of the reservoir, eliminating the need for a plug and abandonment operation. “In this way, we’re extending the field life of a mature asset in a cost-effective manner,” he said. The system also has been deployed in Norway and Brazil.

The MIC system was developed in response to increased demand for lateral flow control, Mr Butler noted. “In the past, if one leg of a dual-lateral well watered out, production from both legs would be compromised. With the ability to control each lateral, one at a time, we can produce a field for much longer, as we have more granular control over the parts of the reservoir we want to produce.”

That step-change has proved beneficial as customers drill deeper laterals, including extended-reach tri- and quadrilateral wells, with legs up to 16,404 ft (5,000 m) long. “The key is to safely expose as much reservoir as possible for as low a cost as possible,” he said. “When we add the main bore and two or three laterals, the average exposed reservoir for a single well can be 33,000-49,000 ft (10,000 – 15,000 m), with flow control for each lateral.”

Early water detection

The increased capabilities of modern computers and high-grade electronics and sensors has had a ripple effect on components and equipment for the subsea market, especially as operators strive to squeeze all the production they can from wells. At this year’s OTC, Emerson Process Management rolled out the newest generation of the Roxar subsea wet gas meter for gas and gas condensate fields.

The enhanced meter provides the earliest possible detection of water in the wellbore, resulting in more accurate production measurement, reduced risk and improved flow assurance, explained Sturle Haaland, Sales Director, Europe, for Emerson. “With more computer power than ever before and the ability to do advanced signal processing at a much higher rate, this advancement was a natural evolution.”

The meter’s microwave-based measurements and multivariate analysis functionality can detect changes in water content in a flowing well at less than 0.2 parts per million, allowing operators to more precisely assess water encroachment. An online salinity measurement system alerts the reservoir engineer when formation water is entering the well.

“Water is the source of all evil in oil and gas production,” Mr Haaland said, noting that formation water breakthrough into a well leads to corrosion, scaling and the formation of hydrates. “In the past, when oil prices were high, operators would estimate how much methyl ethyl glycol (MEG) they would have to inject into a gas well to prevent hydrates, often overdosing to ensure that ice plugs didn’t form at the wellhead and subsequently cripple the line between the well and the transport vessel or LNG plant.”

Today, with every bit of volume of gas really counting, companies don’t have the opportunity to flood wells with MEG because it actually displaces the gas. Additionally, MEG regeneration plants are expensive to operate and maintain. “Companies are operating with more controlled risk than ever before, and with this device they can be certain of water encroachment and save their wells from collapse without flooding them,” he continued. “Even in this market, with low oil prices, there has never been a better time for new technology that can help operators avoid doubt and embrace the risk that comes with maximizing production.”

Click here to watch a video with Robbie Pateder, Director – Lower Tertiary Product Team for Baker Hughes, as he discusses the new Hammerhead system.

Hammerhead is a trademarked term of Baker Hughes. FlexRite is a registered trademark of Halliburton. Roxar is a trademarked term of Emerson Process Management.