The 2015 American Business Conferences’ Houston Wellsite Automation for unconventional oil and gas conference offered a great snapshot of what is, despite the fall in the oil price, a very buoyant sector. While the rig count may be dropping, dealing with the backlog of shale wells is keeping the engineers busy and the size and geographical extent of the new producing areas is providing huge scope for a more digital approach to operations. Although shale wells are kitted out with the same Scada systems that have been used for years, the amount of digital and wireless kit deployed has risen greatly. Operators are also looking at how data is handled downstream and how ‘virtual operations’ can be optimized.
Randall Wilkins (Vine Oil & Gas) observed that although accounting, geoscience and other industry sectors have embraced IT, operations are still often manual. In fact the electronics is already in place, flow, pressure measurement devices are already on the well site generating mountains of data. What is lacking are the right people and processes. An automation team has three components, measurement (devices), the field office (HMI, servers and reporting) and an operations center. The latter is often neglected. One problem stems from inconsistent use of standards. Different sites may use different tank sticks, ‘a nightmare for support.’ Scada systems need to provide meaningful measurement to downstream systems. ‘Software developers need to visit the field, get to know what we are doing and be able to anticipate Scada requests.’
The operations center is the target user group that will enable ‘virtual operations’ (VO). VO is about ‘pumping from the computer,’ operating the field without pumpers writing down the wrong numbers! Scada data needs to be aggregated in the operations center for consistent analytics and reporting. Wilkins believes that maybe 80% of all wells can be pumped from an operations center. This implies rigorous alarm management with zero unacknowledged alarms. Person-specific alarm software that ‘knows who to call’ brings a ‘drastic reduction’ in downtime compared to broadcasting an alarm to everybody. Tank levels and flow rates need to be monitored consistently, ‘tanks cause more grief than anything else.’ Virtual ops enable better communications with haulers for route planning. Site visits can be captured with a $10 ‘last visit’ reset button and timer on the RTU. As operators migrate to the ops center companies need to collaborate with third party visitors, haulers, chemical guys, ‘get them to look around to see if something is unusual and tell us about it.’
Wilkins advocates one operations center, ‘owned by Scada and manned by lease operators’ for each region. Wilkins’ previous employer Exco’s control center brought about a huge reduction in fuel use and improved safety (less trucks on the road and less night work). Virtual operations are cheap to implement although the concept is new and hard to swallow. But the time for the digital oilfield and virtual operations is now! Pumping can be run from head office, ‘I’ve done it. It’s not rocket science.’
Wilkins was pressed on the cost issue in the Q&A. Virtual ops need a significant level of instrumentation and more power to the Scada system, ‘At $40 oil it will be hard to convince management.’ His response was that each investment level will produce a measurable return. ‘As you reduce downtime, claim the money and use it to reduce more downtime.’ In the Haynesville, Exco cut 14 truck routes down to 2 saving $100 per day/truck.
Kevin McDaniel (Marathon Oil) agrees that there is value in virtualized operations but this is ‘just the tip of the value iceberg.’ To use the data fully requires an ‘intelligent oilfield’ approach blending people, process and technology to address efficiency, production optimization and risk management. The goal is to get the right info to the right people at the right time. Data needs to be accessible without driving out to wells. Marathon has replaced its Eagle Ford manual ticketing process in an automation/integration project. This has eliminated risk of theft and loss, bringing data straight into the accounting system. Automated valves allow haulers to punch in a security code, eliminate the need for a complex seal program. Optimizing plunger lift settings is now done remotely and constantly—so that ‘wells stay optimized.’ In all 16 conditions are monitored and alarmed in Scada including flow control valve leakage, dump valve monitoring and plunger travel. Issues can be communicated to folks in the field as actionable items.
Shaun Derise observed that the highest risk to lease operators was ‘windshield time.’ BHP Billiton’s goal is to reduce driving time through exception-based intervention, focusing on preventive maintenance and high value fixes and increasing the well to pumper ratio. This is being achieved through better software—high performance HMI, best practices and exception-based reporting. The scale of modern shale operations can be scary. A comparison with a large offshore facility is instructive. Offshore a 20k bopd production platform may have around 10k data points. Onshore a small platform with three wells, around 1500 data points. But things scale up quickly when an onshore region is considered with maybe 48 pads, 144 wells and 72k data points. Moreover design errors are very costly when you have 48 pads to fix! Derise echoed Wilkins’ comment in his introductory keynote that ‘it’s crazy trying to manage all of the data.’ Derise’s five-point plan starts with a list of daily activity at the well pad that is refined in the context of automation. Site surveys are carried out and plans updated. Production is comingled where possible to reduce equipment costs and installation time. Finally operational philosophies need reworking to leverage the new paradigm. BHP’s push into automation includes IT and communications. Mesh radio connections bring ‘very fresh’ alarms into the surveillance center. The results? In six months, miles driven have been halved and downtime cut by 60%. BHP is to deploy the new system across all its liquid producing areas.
Rene Beck (WPX Energy) presented on the nitty-gritty of Scada deployment. WPX was spun out of Williams Energy in 2012. The company has enterprise Scada deployed since 2009, with now around 7k meters in the system. Beck recommends shooting for a full-blown ‘enterprise’ Scada system management backing. WPX’ Scada is vendor neutral, but ‘we do have Cygnet’ (Weatherford). Scada data goes to applications including Flow-Cal, TOW and Aries as ‘auditable, editable and repeatable data.’ No one size Scada fits all, ‘there will be gaps, make sure the options are there.’ Standardization is to be driven relentlessly, ‘Be as common as possible but as different as necessary.’ In the current climate it is necessary to consider how to handle new basin entries, bolt-on acquisitions and to ask, ‘how easy is it to divest?’ WPX was helped by Techneaux Technology Services and Cygnet. Deployment requires significant investment in project management and support and liaison between IT, SMEs, Scada and communications. ‘Go big or go home!’
Micah Northington showed how Whiting Petroleum has gone beyond Scada visualization into trending and workflow automation. Data is pushed out to more users in the company for operational awareness and is now linked to maintenance systems (Maximo/Avantis/Tabware), production accounting (ProCal/FloCount), finances (Nexus/ADP) and modeling (Aries/OFM). Ideally all these systems should be fed with data from the field, but operating across different localities and cultures can make things hard. Data has to cross the operations/IT frontier via tiered historians the replicate field data to enterprise IT. OPC data forwarding with Kepware also ran as did One Virtual Source. OVS provides a workflow library tying in to over 50 different databases including Scada. A schema metadata analyst standardizes variables and UOM and brings everything together in automated procedures that allow for surveillance by exception.
Joe Rodriquez (ZTR) showed how flexible telematics solutions can be deployed onsite to support data aggregation from wellheads, tanks, generators and be pushed into whatever comms are available, cellular and/or satellite. $40 oil is causing industry to change tack with regards to efficiency, cutting fuel costs through automation. Clients are also going cloud/IP based although ‘security is an issue that we all have to confront.’
Bevan Cox’s (Linn Energy) presentation on RTU selection sparked off an interesting Q&A on whether it was OK to perform a wireless shutdown. ‘Yes!’ opined Cox to cries of ‘no’ from the floor.
On the related topic of wireless availability Kelly Garrod discussed the different options available to remote operators from licensed and unlicensed spread spectrum, cellular and satellite. He recommended Golder’s Squid Pro tool for assessing local cellular coverage.
Heath Jenkins (Wika Instruments) observed that instrumentation seems easy until you have a big field with lots of stuff. There are many choices and options to consider regarding maintenance and complexity. There are also some instrumentation myths, like ‘everything is or should be digital.’ The reality is that Wika sells more analog meters today than ever before! Why? Because they are simple. ‘You don’t need a master’s degree to install or maintain a big dial gauge. And they are reliable. The mean time between failure for an analog stick gauge is 700 years. For a wireless/digital, 100 years so if you have 10,000 tanks, that’s two per week!
Marathon Oil’s Kevin McDaniel explained why you have to ‘sweat the small stuff!’ in meter selection. There are many meter types, turbine, Coriolis, vortex, positive displacement, ultrasonic and magnetic each suitable for different uses. In the Eagle Ford where paraffin is a big problem, ‘some meters won’t work.’ Companies also need to decide what they are going to do with meter data, ‘this is your cash register, inaccuracies in measurement can be costly!’ Meters need a regular proving schedule and solids and water need careful measurement. ‘You may not be able to rely on truckers’ honesty!’ Temperature may vary depending on where a sample is taken. An error of a few barrels per load adds up to several million dollars per year. Use of an API compliant Lact* Coriolis meter supplied by Emerson has mitigated Marathon’s losses.
If you would like to see what kind of kit is used on a modern shale pad checkout the state of the art RTU that was on display from Awc-Inc. This compact field solution includes a Siemens/Simatic real time unit box ready to deploy on a well pad. More from American Business Conferences.
* Lease automatic custody transfer.
© Oil IT Journal - all rights reserved.