As oilfield sensors and digital technologies grow more sophisticated, the industry is increasingly relying on real-time data to optimize the well intervention process. In today’s intervention operations, downhole data can make the difference between success and failure – and we know that operators can’t afford failures in this low-price environment.
Historically, one of the primary reasons for intervention failures is because operators and service providers had to make educated guesses about what was going on downhole, said Lei Fang, Global Product Line Manager-Smart Intervention for Baker Hughes, a GE company (BHGE). These guesses were based on surface measurements. Yet, surface readouts generally don’t provide a full picture of the well’s actual state, particularly in extended laterals, where the intervention could be taking place miles away from surface.
“When you’re doing intervention work, the wells are aging and the condition isn’t always known, so there are a lot of risks associated with the operation,” he said. “Not having data is a big challenge. It can cause nonproductive time (NPT) and a lot of unnecessary events downhole.”
In recent years, service companies have been enhancing the data-collection capabilities of their intervention tools to provide real-time insight on well conditions. This is allowing operators to make on-the-fly adjustments if the intervention isn’t going according to plan or if unexpected events occur downhole. Today’s intervention tools can measure a range of data points, including vibration, temperature, pressure, weight-on-bit (WOB) and toolface inclination. All of these measurements can then be used to prevent costly failures and NPT.
Data analytics are also starting to be leveraged in wellbore interventions, where real-time data can lead to specific recommendations on how to respond to downhole challenges encountered during intervention, Anil Wadhwa, Vice President, Digital, Oilfield Services, for BHGE, said. “It used to be enough to provide real-time data and visualizations during well construction,” he noted. “Over the last few years, the focus has shifted toward ‘answer products’ wherein the data is analyzed using complex algorithms to address specific operational challenges or well conditions.” Such solutions can enhance the quality and reliability of real-time data interpretations and minimize unplanned events by monitoring leading indicators, he added.
Companies could go further still, Mr Fang said, and use data collected throughout a well’s life cycle – not just during intervention – to take a more proactive approach to the intervention. Currently, the industry takes a very reactive approach to intervention, he said. When a problem occurs, a service provider is called to intervene. However, “if we collect enough data over the history of a well, interventions could be more proactive, and big disruptions to production could be avoided,” he added. “To enable that, we’d have to use a large data set collected over the history of the well, maybe even the history of the field. That speaks to a workflow that would need to be established, but there’s huge opportunity yet to be explored.”
Smarter interventions
The urgent need for improved efficiency, which can be seen across all segments of the industry, is driving the application of downhole intelligence during interventions. The worst thing a service company could do in an intervention, Mr Fang said, is to make a mistake that forces the operator to pause either the well construction process or production for any longer than necessary. It’s also become apparent that such mistakes are much more likely if a service company has to intervene in the well without the aid of downhole data. “If you can’t intervene properly, that intervention operation can make things even worse,” he added. “To me, that speaks volumes about the need for downhole intelligence.”
In mid-2017, BHGE launched the xSight Smart Intervention platform to provide real-time downhole insights during intervention operations. The system consists of a bottomhole assembly (BHA) deployed on drill pipe that is outfitted with sensors measuring torque, WOB, pressure, vibration, toolface orientation and temperature. Data is transmitted wirelessly via mud-pulse telemetry to the surface. Communication is bi-directional, so mud-pulse telemetry can also be used to send downlinks to the BHA to change the data acquisition rate or the type of data that’s being acquired. The data is fed into a software program for interpretation, then presented as a visualization. The data feed and visualization can be viewed at the rig site and remotely to access 24/7 advisory support.
As of January 2018, there were three services available through the xSight platform: optimization and orientation, casing collar locator (CCL) and integrated casing exit. The orientation and optimization service provides operators with insight on how the BHA is interacting with the wellbore or casing in operations such as fishing or whipstock casing exits. The CCL service uses density and magnetic measurements to detect the casing collars when an operator is milling or setting packers. Finally, the integrated casing exit service combines the CCL, orientation and optimization services. This service targets deepwater operations. Typically, operators do a wireline run prior to a casing exit to identify where to place the whipstock and mill out of the casing. “With the xSight service, you can identify the casing collar and decide where to place the whipstock, then you can orient the whipstock, and optimize milling parameters, all in one run with real-time downhole data,” Mr Fang said. Because the technology can locate the casing collar in real time via drill pipe deployment, “it allows you to eliminate the wireline run prior to the casing exit,” he added.
The xSight BHA can withstand temperatures up to 300°F and pressures up to 20,000 psi and is compatible with drilling and completions fluids, as well as seawater. To date, the platform has been used primarily for fishing, milling, wellbore cleanout, whipstock casing exits, and packer setting and retrieval.
Recently BHGE deployed the xSight optimization service to work over a deepwater well in the Gulf of Mexico. An isolation packer set at 26,254-ft measured depth had failed, and the operator needed to remove the packer, then abandon and recomplete the well above the failed packer. When the system was run with a fishing assembly to retrieve the seal assembly and anchor latch, data provided by xSight showed 40,000 lb of force being applied on the seal assembly before surface gauges indicated that the assembly was engaged. Had the operator relied on surface readings alone, they would not have realized the assembly was engaged and would have continued to apply weight, which could have damaged the fishing tools on the BHA.
Once the seal assembly was engaged, the downhole data demonstrated that it was released after weight and tension sensors indicated the fish was hanging from the tool string. This provided verification that the fish was actually attached and could be retrieved. Without downhole data confirming a fish is actually attached, operators run the risk of wasting time on fishing operations, Mr Fang said. “You spend a day or two tripping down to retrieve the fish and you think you have it. You don’t want to trip out and take another 24 or 36 hours only to find out that your fish is not there.”
The xSight service can be run with BHGE’s WellLink RT digital platform, which enables real-time remote decision support during drilling and well interventions, Mr Fang said. Launched in 2014, this solution helps in streaming data directly from xSight into WellLink RT for visualization and interpretation at the rig or at customer’s office and BHGE’s remote operations center.
Experts at the remote operations center can see what’s going on in the well and help the rig site personnel decide how to proceed if they encounter a problem during an intervention job, Mr Wadhwa, Vice President, Digital, Oilfield Services, said. “It combines expertise with real-time data to minimize downtime and enhance operational performance,” he said.
Additionally, decision support has become particularly useful in the industry as a lot of expertise has been lost due to the downturn and the great crew change, Mr Wadhwa added. “Much of our current workforce doesn’t have the benefit of decades of experience in the field.” Services like WellLink allow them to collaborate and tap into the expertise of others working in the remote operations centers.
Enhancing capabilities
Schlumberger has been running CT strings embedded with optical fibers since it launched its ACTive real-time downhole coiled tubing services in 2009. Since then, the company has been expanding the operational capabilities of the platform with the goal of providing distributed temperature and vibration measurements in HPHT conditions and while milling and perforating. In March 2017, the company launched a new version of its plug-and-perf ACTive OptiFIRE CT real-time selective perforating and activation system.
The original version of the OptiFIRE system was commercialized in 2015. It allows operators to perforate up to 10 zones in a single CT run. Commands sent via fiber optic telemetry tell the guns when to fire. Once the guns have fired, there is a localized shock detection and a significant increase in pressure and temperature. “Because we have an accelerometer, pressure and temperature sensors at the tool, we can not only detonate those guns on demand, but we also get positive indication to surface that we have, in fact, perforated,” Teoman Altinkopru, VP of Marketing and Technology, Well Services, Schlumberger, said.
However, although this technology could perforate multiple zones in one run, it could not set plugs, so an additional CT run was always required. One of the challenges of setting plugs with CT is that if the plug doesn’t fully set, the CT string could end up stuck in the well, Mr Altinkopru explained. “When the plugs don’t fully set, it can be due to an issue with the casing, debris and frac sand left in the wellbore, or a malfunction of the plug itself or the setting tool,” he said. This creates a situation where the plug hasn’t detached from the tubing string because it didn’t properly set. However, because it is partially set, the plug and CT are essentially stuck. “Now your well is full of coiled tubing, it has live guns and a half-set plug you can’t come off of, and it can’t be dragged to surface.”
To outfit the OptiFIRE system with the capability to set plugs, Schlumberger developed a release mechanism that, when activated, releases the plug so the CT string can be retrieved from the well. The release command is conveyed through fiber optic telemetry. This allows operators to use the system to set plugs and perforate in a single run, Mr Altinkopru said.
The system was deployed in a shallow-water well in the Nene Marine field offshore Congo for Eni in 2017. In the first well in the development, three separate runs were required for setting the plugs, perforating the well, and then cleaning it out. Schlumberger deployed the plug-and-perf ACTive OptiFIRE system in a later well in the field.
Deployed with the ACTive Perf service, the ACTive OptiFIRE perforating and activation system can detonate up to 10 perforating guns in a single run. To outfit the OptiFIRE system with the capability to set plugs, Schlumberger developed a release mechanism that, when activated, releases the plug so the CT string can be retrieved from the well. The release command is conveyed through fiber optic telemetry. When deployed in an operation offshore Congo, the system eliminated two CT runs and saved the operator 36 hours in rig time and $600,000, according to Schlumberger.
The system was run into the well with a BHA comprising a Schlumberger Copperhead drillable bridge and frac plug, the setting tool, 3 1/8-in. perforating guns and a CCL. In one run, the plug was set, the guns were fired and their detonation was confirmed. The process eliminated two CT runs and saved the operator 36 hours in rig time and $600,000, according to Schlumberger.
The company is working to further optimize CT interventions by developing a new power delivery mechanism for its ACTive platform. Currently, the platform is powered by lithium batteries, which limits how long the CT string can be in the well. However, the company is now field-testing its Inconel Fiber (IFC) power technology, which integrates copper wiring into the CT string alongside the optical fibers used for telemetry and distributed measurements.
“Our downhole time will no longer be limited to the life of the battery because we have continuous power being sent from surface along the length of the IFC to the downhole tools,” Mr Altinkopru said. Not only that, but storage and disposal of lithium batteries are expensive. They can also be difficult to ship, and some airlines will not ship them due to their potential for overheating and catching fire.
Field testing is being conducted in the Middle East and North Sea, where the ACTive platform is heavily utilized, Mr Altinkopru said. Schlumberger aims to commercialize the technology by end of 2018.
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