For every record-busting lateral length or ultradeepwater discovery, production technology has to evolve to meet the new challenges, helping operators keep an eye on efficiency to get the most bang for their bucks. In the last five years, trends have emerged to improve real-time monitoring, artificial lift and EOR. As these technologies pick up speed, the industry is keeping pace developing each technology to address new production challenges.
Fiber-optic sensing for downhole monitoring has been used since the ’90s. Measurements came from single-point sensors, which provided data—temperature or pressure—from one particular point in the well and used the fiber-optic cable to transmit the information. Advances in fiber-optic technology, however, have expanded the range of applications for these cables.
Distributed acoustic sensing (DAS) allows fiber-optic cable to collect acoustic data along its entire length, creating a continuous sensor that can be as long as 50 km (31 miles). The sensitive, cost-effective technology provides real-time monitoring of well operations for the life of the well, including fracturing operations, leak detection and equipment condition monitoring.
DAS has been gaining ground in the industry over the past five years, making the transition into permanent flow monitoring applications and into development for subsea work. Shell and QinetiQ notably teamed up in 2009 to focus on DAS product development, performing the first field trial in February 2009 and announcing a collaboration in 2010 to exploit QinetiQ’s OptaSense DAS systems.
Late last year, Shell and OptaSense revealed plans to develop the industry’s first fully marinized and qualified DAS system. The Subsea-DAS system will be deployed in water depths of up to 3,048 m (10,000 ft) and will be able to provide acoustic data for myriad subsea and deepwater applications, including in-well monitoring, subsea assembly condition monitoring and permanent reservoir monitoring. According to a press release, the marinization process will require the reengineering of OptaSense’s existing DAS interrogator unit to fit into a pressure canister and testing of the modified opto electronics to ensure they meet the temperature, vibration, shock and electrical certifications required for subsea technology.
Most recently, in September 2014, the collaboration announced the delivery of the first permanent DAS in-well production flow monitoring system. The DAS-Flow system constantly monitors a well through on-demand measurements of flow along the length of the wellbore, a press release said.
“There is a high potential optimization value to be realized within the industry with the advent of more detailed flow information across individual well production and injection zones,” Magnus McEwen-King, managing director of OptaSense, said in the release.
Silixa Ltd. also is active in the DAS market with its Intelligent DAS (iDAS) technology, with an investment in 2012 from Statoil Technology Invest and Chevron Technology Ventures to begin global commercialization of the technology.
Microseismic monitoring is a relatively new commercial process in oil and gas, and as it gains traction, companies have been working to optimize its use in completions evaluation. Rather than simply spreading perforation clusters out evenly, operators have found that using data to design the completion can help provide the most contact with the reservoir. Traditional frack design can leave some clusters unreached by fluid—where microseismic events are missing during fracturing. Operators can use microseismic monitoring to plan where to place clusters or to determine which areas will take proppant more easily, with less pressure.
MicroSeismic Inc., the company that commercialized surface microseismic monitoring, continues to push forward in the industry. The company released several new technologies this year for real-time analysis for completion evaluation. With analysis in real time, operators can make adjustments at the well site to optimize production.
MicroSeismic Inc. also has recently launched technologies to optimize completions and manage reservoirs stage by stage. PermIndex, a microseismic-based permeability tool, gives permeability estimates for each frack stage as well as data-driven constraints for reservoir simulation to improve production forecasting. Using radial pressure fronts of microseismic events during fracking, PermIndex calculates effective system permeability and helps operators understand the reservoir permeability on a stage-by-stage basis without needing to run a production log. The FracRx service combines microseismic data with pump and geological data, which allows the technology to track the growth of the fracture network in all directions and then discern how the fracture area grows with injected fluid volume, a product announcement said. The goal is to increase asset values by optimizing the treatment of each well. Operators can identify and react to fault reactivation, better understand drainage near the wellbore, evaluate whether the treatment is opening existing fractures or creating new ones and make certain that the treatment is staying in zone.
MicroSeismic Inc. certainly isn’t the only player in the game, though. Schlumberger launched a new microseismic surface acquisition system this year to optimize completion design: MS Recon. The system is for surface and shallow grid microseismic surveys and is designed to improve signal-to-noise ratio during acquisition for enhanced imaging of the fracture geometry. MS Recon has a geophone accelerometer and ultra-low noise electronics for a wide range of signal detectability, according to a product announcement. Field trials have shown that the MS Recon improves sensitivity to smaller microseismic events compared to a conventional system.
Pinnacle Technologies, a Halliburton service, came up with a tool that combines microseismic receivers with the company’s downhole tiltmeter sensors to determine fracture height. FracHeight uses the measurements of formation movement associated with fracture dilation in addition to the microseismic data to help identify the cause of microseisms.
ESG Solutions integrated downhole microseismic with surface and near-surface induced seismicity arrays in its Hybrid Seismic Sensor Network to evaluate large- and small-scale seismicity for hydraulic fracture monitoring. This allows the system to capture large magnitude events and time-synchronize the data with downhole microseismic data, giving operators new information about fault activation and fracture effectiveness.
“Accurate measurement of larger events allows clients to correctly assess the role of faults when interpreting fracture behavior and reservoir deformation,” said Dr. Ted Urbancic, executive vice president of energy services at ESG Solutions, in a press release. “Larger events release more energy into the reservoir. In multiple cases, we have seen a handful of these larger events representing as much as 70% of the total seismic energy released over the stimulation program. This has a profound effect on the way operators evaluate their treatments and presents a unique view of hydraulic fracture stimulations not previously considered.”
Electric submersible pumps (ESPs) have long been used in conventional wells for artificial lift, and as the industry is confronted with new lift challenges, innovators are adapting ESPs to solve problems in harder-to-produce areas.
One disadvantage of ESPs is the need for frequent intervention. Offshore, the limited availability of workover vessels complicates the matter. To reduce intervention time, cost and nonproductive time, rigless ESP stings have been adopted in the past few years. The technology was developed by Artificial Lift Co.—now AccessESP—and ConocoPhillips and commercialized in 2010. The first one in the Middle East was installed at a Saudi Aramco-operated field in 1,865 m (6,119 ft) of water by Artificial Lift Co. in 2012—an advance noted in the E&P year-end production review that year.
The Advantage Rigless ESP System from AccessESP is a through-tubing, slickline-conveyed lift system. The Advantage system includes a 134-hp permanent magnet motor and the company’s wet connect system. This year, the company deployed its system for Total E&P Congo in the Republic of Congo. Total plans to include the Advantage system in future wells, a press release said.
Baker Hughes, which formed the Subsea Production Alliance this year with Aker Solutions, has taken a rigless ESP system into the deepwater of the Gulf of Mexico (GoM). In May, the company brought online two subsea ESP systems at the Cascade Field, operated by Petrobras America Inc. in the Lower Tertiary trend of the GoM. According to a press release, the subsea boosting system is in 2,500 m (8,200 ft) of water and employs two ESP systems that operate hydraulically in series but electrically in parallel. They’re housed in a replaceable cartridge placed on the seafloor, and no rig is needed for intervention. The system’s designed to a working pressure of 12,500 psi, flow rates from 3 Mbbl/d to 20 Mbbl/d and 1.3 MW.
“We have successfully installed in-well and seabed ESP boosting systems offshore Brazil, in the Gulf of Mexico, in Asia Pacific and in the North Sea,” said Peter Lawson, Baker Hughes director of artificial lift technology, in the release. “This latest successful deployment of subsea ESP systems continues to increase the industry’s confidence in ESP technology as a critical part of subsea production systems.”
Though CO2 EOR has been applied to reservoirs for decades, next-generation solutions have more recently been the focus of R&D with the goal of applying CO2 EOR to new areas, such as residual oil zones and offshore fields. In 2010, the U.S. Department of Energy chose seven next-generation CO2 EOR research projects that are now in various stages of progress. Four of these projects are working on techniques for mobility control of the injected CO2, including two using nanoparticle-stabilized foams. The others focus on CO2 injection for residual oil zones or developing simulation and modeling tools for CO2 EOR.
Microbial EOR also is being explored. DuPont’s MATRx EOR technology uses microbes and nutrients customized for each oil reservoir. The process exploits the native microbe population to maximize oil recovery by identifying microbes in each reservoir that facilitate bioplugging and reduce residual oil saturation, according to the company. The reservoir can then be inoculated with the favored microbes.
Glori Energy has extended its technology partnership with Statoil to optimize and expand its AERO System. The system stimulates the naturally occurring microbes in a waterflooded field’s reservoir to improve water sweep and oil mobility. The system activates specific microbes that reduce interfacial tension between oil and water. Biomass from microbial growth is produced where the oil is trapped, which results in changes of water flow patterns at the pore level and frees up more pathways for oil flow.
Five years ago, organizations like OPEC and the International Energy Agency predicted in their 2009 yearly outlook reports that carbon capture and storage (CCS) technology would become increasingly important in the coming years. Though large-scale commercialization and adoption is slow, progress is indeed being made.
Capturing CO2 from power plants has environmental benefits, and combined with the economic benefits of using the CO2 for EOR purposes, the CCS technology that has long been available is being put into use in larger applications. In September, SaskPower’s Boundary Dam coal-fired power plant in Saskatchewan, Canada, began capturing CO2, making it the world’s first large-scale power station with CCS technology. The plant is expected to capture about 1 MMmt of CO2 per year, which will be injected into nearby oil fields for EOR.
The Global CCS Institute recently released its annual review of the CCS sector, which said that the construction and operation of CCS facilities across a range of industries has doubled since the beginning of the decade. Mississippi and Texas are anticipated to launch CCS facilities in the power sector in 2015 and 2016, respectively. Mississippi Power’s Kemper County Energy Facility in Mississippi will use a precombustion capture technique, while the Petra Nova Carbon Capture Project at NRG Energy’s W.A. Parish power station in Texas will demonstrate a postcombustion technique. Kemper County, Petra Nova and Boundary Dam are all using capture methods from different technology suppliers.
“With large-scale CCS power projects now a reality, an important milestone in deployment of the technology has been achieved,” The Global CCS Institute said in “The Global Status of CCS: 2014” report. “This means that it is time to move discussion onto how CCS can best be deployed as part of a least-cost approach to climate change mitigation. We can now move on from arguments about its ‘experimental’ nature or that it has not yet been applied at scale to fossil fuel power plants.”
With a few more years and some more investment—Kinder Morgan Energy Partners just invested $1.7 billion to build new CCS projects for EOR use in the Permian Basin, and NRG’s Petra Nova project was estimated at $1 billion—CCS could be the game-changer the industry’s been waiting for it to be.