Wired drill pipe has been a long time coming. As operators look at cost savings across the full life cycle, the benefits are now being recognized, says NOV’s Leon Hennessy.
Drill floor operations. Photo from NOV IntelliServ.
Wired drill pipe (WDP) is conventional drill pipe modified to accommodate an inductive coil embedded in the secondary shoulder of both the pin and box end. These coils are connected via an armored, high-strength DataCable embedded inside each tool joint, enabling high-speed downhole data to be transmitted across the drill string. DataLink sub-assemblies, typically placed every 1500ft along the drill string, clean and boost the data signal for optimal signal-to-noise ratio along the network.
The main benefit of WDP is to enable a reduction in telemetry related flat time, i.e. any time that is spent off-bottom waiting on mud pulse telemetry to send a signal to surface. Any drilling operation using measurement while drilling (MWD), logging while drilling (LWD) or rotary steerable systems (RSS) tools in the bottomhole assembly (BHA) will often see this time occur. This could be during surveys, on connection or mid-stand, during check/roll surveys, while downlinking off-bottom or shallow hole testing, during pressure testing, formation integrity testing, leakoff testing, signal trouble shooting, etc.
Figure 1 – Well A Telemetry Time Savings Analysis (hours)
Although individually these instances makeup a small time component, once accumulated across an entire well, this value can add up to multiple hours or even days. Oil major Total, in Norway, recently published telemetry time reduction results (ref: SPE 178863, 2016) that it realized from implementing WDP in its operations at the Martin Linge field, where there was a 82% reduction in normalized telemetry time per well.
WDP offers other benefits, including increasing rate of penetration (ROP) through high frequency, low latency downhole data, allowing real-time optimization, and enhanced real-time visualization and monitoring of equivalent circulation density. These benefits can be enhanced further with the use of along-string measurements including pressure measurements, to manage wellbore conditioning and time spent circulating off bottom. Real-time data can help improve well placement and geo-steering on-the-fly and reduce unplanned bit and BHA runs by detecting drilling dysfunctions early.
A recent five-well development campaign on E.ON Ruhrgas’ Babbage field (ref – SPE 178798, 2016) used WDP to add value. Apart from the telemetry time savings of 25.8 hours per well, a reduction in runs to total depth (TD) of more than 40% was identified, as well as a 200-300% increase in ROP.
Figure 2 – Well B Telemetry Time Savings Analysis (hours)
Total’s operation on Martin Linge also saw increased reservoir drain of 1000m through ECD (equivalent circulating density) limits optimization versus shoe strength. It also had a nearly five-fold increase in ROP, instant activation, and confirmation and de-activation reaming tools. Enhanced reservoir appraisal was enabled through use of seismic while drilling look ahead, activation and data transfer through WDP, which net an increased drain in the sweet spot.
While the upfront costs might seem like a hurdle, calculating the costs against the benefits needs a closer look.
WDP cost, or cost to a project, can be outlined as:
- Cost of WDP – The capital cost or rental cost to the project
- Inspection, repair and maintenance (IRM) – Additional electrical inspections, replacement of coils and DataCables, which measured in the business case and is an incremental percentage increase at the nominal inspection cycle for a particular project
- Telemetry network management – Any costs associated to managing the network including service company charges for supplying the interface sub so that all their MWD, LWD and RSS tools operate on the network
- Wired Tools – Wiring cost or additional rental cost of wired tools in the BHA compared to conventional (non-wired) BHA tools
- Network maintenance and uptime – The small time component related to any maintenance on the network
For the cost of WDP, wired tools and the IRM components, these can be considered incrementally above the traditional cost of the string since these are existing costs.
Figure 3 – Telemetry and Value Add Savings (days)
For an initial value analysis, it is acceptable to look at nominal well designs and project inputs. If further data is available, it is important to conduct proper off-set well analysis to clearly verify the telemetry time savings and further model the potential value-adds against the well construction challenges. Traditionally, any value-add assessment will include a Monte Carlo analysis to fill any probabilistic scenarios, such as an increase in on-bottom performance in order to provide a more realistic output. Typical data used are BHA designs, daily drilling reports, bit run reports, MWD and mud loggers’ end of well reports, well summaries and definitive surveys, time-based drilling mechanics logs, activity summaries with planned vs actual time depth curves and slide sheets and landmark exports.
The business case
Below is an example from an ongoing field development project in Asia Pacific. The business case has been supported with a two off-set well analysis.
The following main assumptions are considered when calculating the net value:
- A five-year nominal string life and depreciation schedule
- US$350,000 nominal spread rate
- 45 average day wells
- A rotating hours nominal inspection cycle interval per 2500 hours
- Incremental investment costs considered from the provided BHA as listed in the analysis
Identify savings potential
The well analysis of wells A and B identified multiple telemetry time events, which were quantified from the time-based logs and summarized in Figures 1 and 2. The telemetry and value-add savings are outlined in Figure 3. The focus of the analysis is purely on the automatic telemetry savings which does not discuss value-add savings in detail.
Incremental cost and operational expenditure
Figure 4 – Operating Expense per Annum
The cost of WDP takes into consideration the incremental purchase cost of a wired string, i.e. the cost above the conventional or unwired string. The main string components considering a nominal well design as referenced above include:
- 5 7/8in wXT57 Range 2 – WDP and wired HWDP
- 6 ¾in wired drill collars, NMDC and ponys
- 8in wired drill collars, NMDC and ponys
- 6 ¾in and 8in wired stabilizers and reamers
- Additional IntelliServ network integration equipment:
- Integrated top drive DataSwivel
- Wired saver subs
- Surface cabling (from DataSwivel stator through service loop and down the derrick to the mudlogging/MWD unit)
The total incremental cost of the wired BHA was $1.68 million, or when depreciated over the life of the string on this project, $42,000 per well.
In addition, there are several telemetry components provided by IntelliServ to create the high-speed telemetry network using the wired drillstring. This includes a Network Controller, the DataLinks, WDP inspection, repair and maintenance, MWD interface subs, and field technicians.
The total normalized annual cost of owning and running WDP is outlined in Figure 4 and equates to $220,000 per well.
Figure 5 – Commercialized Net Value
Commercialized net value
Furthermore, Figure 5 shows that after paying for the $220,000 per well, $187,000 of savings will be realized. Given this is considering simply the telemetry related savings alone, any further value driven by WDP – for example value-adds such as increased on bottom performance, reduction in Bit/BHA runs etc. – will further increase the net value realized. In the cases referenced in this discussion for Total, Martin Linge and E.ON Ruhrgas, Babbage the value-adds were compelling and measurable.
Learn more about wired drill pipe in OE’s next expert access webinar on 15 September, at 11AM CST. Join author Leon Hennessy and Brian Van Burkleo as they discuss how to deliver project value with wired drill pipe.
Visit OEdigital.com to register today.
Leon Hennessy is business development manager for Asia Pacific and Middle East Regions for IntelliServ. With a career spanning drilling operations and directional drilling, Leon has hands on experience throughout the life cycle of well construction. Prior to joining NOV, he founded an integrated services business providing geology, reservoir, drilling engineering, directional drilling and operations services.