HPHT, remote environments push demand for more monitoring options, higher-rated systems
By Joanne Liou, associate editor
To improve reservoir management and recovery, understanding how the reservoir is going to produce based on downhole data and using the right completion equipment is key. Gaining ground onshore and offshore, from remote locations to high-pressure environments, intelligent well systems (IWS) are keeping pace with industry challenges and providing capabilities to remotely control wells and monitor downhole conditions under an automated system.
Offshore: Remote completions
Since the Gulf of Mexico’s (GOM) first intelligent completion in 1998, increasing pressure and temperature demands – from 250°F to 350°F and from 10,000 to 12,500 to 15,000 psi – are driving a continued evolution in IWS technologies. “The dramatic changes have forced tool suppliers to utilize exotic materials, such as nickel alloys, for higher strength and pressure/temperature ratings, to reserve real estate to maintain large-bore production profiles,” Dewayne Turner, manager of completion tools development at Superior Energy Services (SES), said.
“By using the exotic materials that have a higher yield, large bores can be maintained or maximized,” Bernard Franklin, director of technology at SES, said. “This offers more area for flow of produced or injected fluids.”
An intelligent completion provides a means of selecting and controlling multiple producing intervals from a remote location. Remote operations vary from surface control units to software-operated POD systems. SES has developed a new HPHT Hydraulic Actuated Well Completion (HAWC) system targeting deepwater and ultra-deepwater selective applications, including the GOM Lower Tertiary formations. The system is suited for environments where temperatures exceed 300°F with formation pressures up to 15,000 psi. The company’s existing 12,500-psi HAWC system rated to 250°F provided the framework to develop the higher-rated system. “Equipment suppliers are challenged to exceed expectations by developing equipment that reduces risks to extend the well’s production life,” Mr Turner said.
An intelligent HAWC system is the production control system in a well, where each interval has tangible hardware adjacent to the perforations and service tools that were used for stimulation and media placement. Fluid loss control (FLC) and/or production valves function to address construction phase issues, then open to provide tubular communication to the formations. “They are debris-friendly sleeve-type valves with an open through-bore, minimizing the collection of foreign particles. FLC valves are balanced during stimulation treatments, which prevents premature hydraulic actuation,” Mr Turner explained. The valves become pressure-sensitive upon landing the production tubing with a HAWC system. Because the FLC valves are internal pressure-actuated and the HAWC valves operate remotely through control lines, production is achieved by pressure cycles. “This process is known as an interventionless method because production is achieved without mobilizing coiled tubing or braided line,” Mr Turner added.
With the HAWC system, “production initiation is interventionless, packer setting is interventionless and manipulation of sleeves to control flow from either zone or commingling of two zones or more is interventionless,” Mr Franklin said. “Essentially, that would make up intelligent completion.”
SES has designed a new isolation packer and hydraulic sleeves for 15,000-psi operating environments. “Proprietary seals reduced operating friction yielding a lower operating pressure. The sleeves have larger bores and are more debris-tolerant than previous models,” Mr Turner said. “An improved mechanical choke and unloader produced positive results in hostile testing territory. The in-string production packer is a hydraulic-set removable V-Zero rated, 15,000-psi qualified packer.” Control line passage through the packer has been simplified, and the performance envelope recognizes 15,000-psi differentials up to 140,000 lbs of tensile or compression, Mr Turner explained.
HAWC valves were qualified using the same leak-off criteria specified by API in the V-Zero specifications. The valves were qualified by functioning in various temperature and pressure surroundings and by opening them with internal and external differentials to replicate downhole conditions. Then, the valves were tested while monitoring gas leakage. The unloader seal stack seals or isolates tubing to formation communication. Sleeve shifting with internal or external differentials tends to damage the unloader seal stack. Combining a mechanical choke, to prevent the flow of gas under or around the seals, and the mechanical design of the equalizing flow path, proved to extend the HAWC’s sealing life, Mr Turner explained. “Wipers were incorporated to halt foreign debris entry, and an alignment key aligned the inner and outer parts, preventing internal sleeve rotation and ensuring slot alignment to reduce erosion.”
Once the HAWC is deployed, production is achieved without intervention. Packer fluid is circulated in place and an underbalance is created; then the packer is set and tested. Internal pressure is applied with the upper hydraulic sleeve closed and the lower sleeve open. Pressure reaches down the lower interval flow path to shear the upper and lower intervals FLC valves. The upper interval FLC valve opens immediately and can be observed on surface displays from the downhole gauges. The lower interval FLC valve opens as applied pressure is released. Once the applied pressure is less than or equal to the lower interval formation pressure, the valve will open and the well will begin to produce. Switching intervals is accomplished by pressurizing the closed control line to cycle an open sleeve to the closed position, Mr Turner explained. After venting all line pressures, the desired open control line is pressurized to open the desired interval. Control line pressures are vented and blocked during production.
The key to successful deployment and meeting project needs on an IWS completion is to engage with the operator early to ensure all surface and subsea equipment accepts additional control lines, SES believes. “Operators are committed or limited once the subsea tree is on the ocean floor,” Mr Turner said. “Control lines and line penetrations along with software packages and hydraulic valves inside control POD’s limit options after tree deployment.”
SES currently has several HAWC systems on order targeting intelligent completions in the GOM, and it expects to deploy the 15,000-psi system in mid- to late August. It will be the first commercial deployment for the new higher-rated system.
Looking toward the future, Mr Franklin said he believes ultra-deepwater and the GOM Lower Tertiary will continue to drive the demand for the next IWS generation. “Selective multizone completions utilized to complete extended pay 500 ft to 3,000 ft can and will utilize intelligent well technology. HAWC-type systems will need to be incorporated in the sand face and be integral to the equipment to maximize and optimize selective production,” he said.
Onshore: Data collection, calculation
Enhancements in surveillance equipment and software also have emerged in IWS technologies to provide real-time pressure and temperature data for each zone in onshore wells. “Intelligent platforms provide automation systems that include local control and centralized software that can collect information around the well,” Alan Hinchman, vertical marketing director for infrastructure line at GE Intelligent Platforms, explained. “In the case of drilling, you have a tremendous amount of gas and/or liquid measurement data that is transmitted over radio, cellular and satellite systems. If you have drilling operations in Utah, Wyoming, Oklahoma or Texas, that data is archived in a central repository for analysis.”
In onshore natural gas plays, for example, calculations based on IWS-collected data can help monitor production quantity and even the quality and other organic compounds present in what’s being produced. Wells push information to a historical database, which can be read at the well site using enabled mobile devices. Examining an entire field would provide operational data, such as flow rate, pressure and temperature. “You take this information, pull it together into a package and send that up to a centralized area,” which could be as simple as an on-site trailer, Mr Hinchman said.
GE recently released the PACSystems RXi industrial control platform to collect remote data to centralized locations. Using WiFi and Bluetooth connections, it allows the operator to connect to remote areas without having to plug in a separate laptop and eliminating ancillary products, Mr Hinchman said. GE also released an iPad application to provide real-time operational intelligence, where controllers on the well site feed data about how the well is running to a central depository and to the iPad. The application, which stores key performance indicators, connects to software that is collecting the information from the RXi platform.
Data storage also is evolving with the development of cloud-based storage. GE is working on moving to a cloud-style interface for flow controls and expects to launch a cloud concept within the next year. “Once you plug into our units, you’ll be able to pull up the information on a web browser through a secure link and be able to integrate or interface with them,” Mr Hinchman stated. “We’re rapidly moving to an open-cloud concept, which does create some security challenges that we’re solving.”
Rapid deployment and lower costs are driving factors behind the cloud. “Instead of providing a computer to everyone, it’s the ability of having a smaller cost footprint and being able to provide different products and operational experiences to different operators of the same data sets,” Mr Hinchman explained. “Operations may have a different view from the executives or the people drilling and the geologists, but they all play off the same data sets, and they are all updated on the same thing.”
As monitoring tools become more integrated into IWS technologies, Mr Hinchman foresees another challenge of utilizing all the data collected. “Once you get all this data back, what do you do with it? In two to three years, we’ll have the data capability of pulling out information, predicting what’s going to happen,” he noted. “We’re working on a solution to handle big data and how to make sense of that to a predictive area. The last piece is providing that information back in a simplistic format through the cloud.” Big data refers to hundreds of thousands of data points being collected from assets in the field. As data is collected, it has the potential to provide information about the assets – how they are running, do they need maintenance, etc. “Then the operator can do something about that status before a failure occurs,” he said.