Hess Pilots Automated Drilling Rig in the Bakken
Trent Jacobs, JPT Senior Technology Writer
A pilot project carried out by Hess Corp. demonstrates just how quickly automated drilling technology is able to take a rig from the bottom of the pack and push it to the top.
In November 2014, the company selected a rig from its Bakken Shale fleet that had been in the bottom quartile in terms of performance for more than 2 years. But over the course of a 16-well program, the rig became the second fastest Hess had working at the time. Year-to-year comparisons showed the automated rig had improved its drilling footage per day by 24% compared with the fleet average of 17% over the same period.
Despite the apparent success of the project, the industry downturn forced the company to lay down the rig last year. Details of the pilot were discussed at a meeting of the SPE Gulf Coast Section in January in Houston. The technical paper summarizing the results will be presented at the IADC/SPE Drilling Conference and Exhibition this month in Fort Worth, Texas (SPE 178870).
The system, supplied by National Oilwell Varco, used a downhole automation system that controlled the auto-driller system on the rig. Wired pipe delivered high-speed data between these systems and tools that measured key parameters, including downhole weight-on-bit, torque, and vibration. Matthew Isbell, a drilling optimization adviser at Hess, noted that the wired pipe delivered so much information that it was a challenge to handle it all.
“The data fire hose overwhelmed us, both in terms of analyzing the run as it was happening as well as at the end of each well and trying to figure out what we should modify on the system for the next well.” He added that one of the goals of any future automated pilot is to come up with a way to better visualize the data to make the process of understanding it more efficient.
Keith Trichel, a drilling engineering adviser at Hess, said the original plan for the pilot was to simply turn the system on and observe how it functioned without asking the rig crew to take action on the real-time data streaming out of the well. “But to our surprise, the rig crew and the folks involved in the drilling process really quickly grasped what they were seeing and started reacting to it,” he said.
With the ability to see what was taking place downhole, the rig crew began using the automated equipment as a learning tool. This enabled them to use the data to run on-the-fly experiments to achieve performance improvements and see problems sooner.
One key discovery the crew made was that they could speed up the rotation from the standard 45–50 rev/min to 90 rev/min. By speeding up the rotation, the drillstring became more stable and allowed the vertical section to be drilled in one run vs. the usual two. Other Hess-operated rigs in the area followed their lead and made similar performance gains.
The pilot also showed that as certain gains are made, unexpected problems may be introduced. The major issues Hess faced involved increased wear on the bits due to the rate of penetration and the bottomhole assembly’s tendency to “drop,” which occurs when bit force is placed on the low side of the well while drilling the curve.
The pilot had aimed to generate enough time savings to break even on the cost of the automated system but achieved this on only six of the wells drilled while six other wells missed the target by less than USD 100,000. The overruns on the other four wells were chalked up to “trouble time” in the curved sections and time lost trying out different bottomhole assembly units to address dropping issues.
The downturn had other unexpected effects on the project. Isbell said the drilling team had wanted to limit variables as much as possible. But because of “industry unrest” and turnover, the automated rig had three different drilling superintendents, four different drilling engineers, and six different company men come and go over the course of the project.
Payoff Still Possible in Refracturing Conventional Wells
Stephen Rassenfoss, JPT Emerging Technology Senior Editor
There has been a lot of talk about refracturing recently, but the percentage of wells fractured more than once is a small fraction of the 35% rate from the 1950s to 1970s.
That statistic came from a recent presentation by Anton Babaniyazov, a staff production engineer for ConocoPhillips, who used it to begin a talk for the SPE Gulf Coast Section’s Permian Basin Study Group about a successful fracturing campaign in west Texas.
The wells were in conventional reservoirs in the Permian Basin, some dating back to the mid-century years he referred to as when far fewer wells were fractured but a significant number were refractured, often multiple times. The point was that there is money to be made on the oil left behind in reservoir rock that is of far higher quality than the unconventional rock layers, which have gotten far more attention and investment in recent years.
“With the growing numbers of aging wellbores, rework in the existing zones such as refracturing helps to reduce temporarily abandoned well counts, increase production rates, and often reserves,” he said, adding, “the ‘rework inventory’ remains high and economically attractive for Permian Basin operators.”
A campaign in 2010 and 2012 covering more than 70 wells yielded an 80% success rate, which Babaniyazov defined as a production gain that allowed payback on the investment within 6 months to a year. The cost varied because the nature of the work ranges from acidizing to refracturing or deepening the well. While the latter options cost more, they also offer higher potential gains.
The price collapse has put the program on hold at a time when spending has been slashed, and the outlook is uncertain because prices for oil and services are so hard to predict. “When I was involved, it was USD 50/bbl and now it is what, 29 a barrel?” he said during a presentation in mid-January. “USD 30/bbl is not the same as USD 50 bbl.”
ConocoPhillips’ campaign was started because it had a significant number of wells dating back as far as the 1960s, when production had dwindled to the level at which the company needed to spend to increase the output or plug and abandon the wells.
A way was lacking to identify which of the wells would be candidates, and rank which offered the greatest potential payoff. There was limited industry experience to draw on. Industry reports on refracturing tend to focus on successes, with little data available about the ones that had failed and the causes.
The answer to the question was complicated. Based on the slides shown during Babaniyazov’s presentation, screening required answering many questions. At the top of the list: Are there significant volumes of good quality reservoir that have not been tapped. He said a study showed wells in the Permian in which 30% of the reserves had been bypassed.
The condition of the steel casing and cement around it is also critical. A cement bond log estimating that 95% of the cement is sound leaves enough room for a channel that can divert fluid and undercut the effectiveness of the fracturing work.
The targets were a mix of new and old. Some aimed at hitting newer reservoir rock in higher-pressure zones, others were designed to improve the output from older reservoir sections in which flow assurance was often a problem. Refracturing could open production pathways where there has been “degradation of fracture conductivity over time.”
The success of the program required cooperation among a wide range of exploration professionals, from geologists seeking out untapped rock to fracturing engineers considering the best way to divert fluid so it reached the targeted areas. Success also depended on training the field staff to gather the critical information, such as doing mini-frac tests to measure localized pressure levels, which are needed to evaluate the local formation pressure levels required to assess the potential refracturing yield.
The system may still be of use in what will be a period of extended low prices, but that will have to be verified.
“You have time to go back to the drawing board,” Babaniyazov said. Technical and economic success will require using this analysis to determine the risks and rewards of refracturing, ensure the well is sound, and identify which diversion techniques are the best options.
Drawdown Management Critical to Mitigating EUR Losses in Shale Wells
Stephen Whitfield, Staff Writer
The increase in production from hydraulic fracturing operations in recent years has had a dramatic effect on the oil and gas industry. However, as shale plays have taken up a larger percentage of the overall market, annual decreases in estimated ultimate recovery (EUR) values for shale wells is now a major concern for operators.
At a presentation hosted by the SPE Gulf Coast Section, Ibrahim Abou-Sayed discussed how the adoption of drawdown management strategies have helped mitigate and reduce these losses.
Abou-Sayed, the founder and president of i-Stimulation Solutions, also spoke about the elements of drawdown management that have been found to have the most significant impact on shale well productivity.
In the presentation, titled “Shale Well Drawdown Management and Surveillance to Avoid EUR Loss and Impact on Refracturing,” Abou-Sayed listed several parameters that affect production management strategies. Among them were the permeability of the formation and various types of pressures, such as the initial reservoir pressure, the pressure at the safety relief valve, and the closure pressures on the hydraulic fracturing proppant and unpropped fracture surfaces. Abou-Sayed said downhole flow pressure, reservoir pressure, and choke size are the parameters over which operators can exert the greatest control.
“When you are locating the reservoir or reducing the downhole pressure, you are putting more closure pressure on the proppant, and you are closing the nonpropped fracture,” he said. “You have to take all of that into consideration, otherwise you will see your productivity go way down very quickly.”
Abou-Sayed discussed the Haynesville Shale Development Program. Launched by Exco Resources in March 2008, the program sought to increase production in the Haynesville Shale reservoir located in east Texas and northern Louisiana.
The Haynesville shale was determined to be soft and friable, potentially supporting proppant embedment and negatively impacting production. As a result, the company implemented a controlled drawdown strategy in the wells’ early lives. The methodology involved the development of a maximum drawdown limit based on well depth, reservoir pressure, bottomhole flowing pressure, and critical closure stress on the proppant pack.
After initial testing on some of its vertical wells, Exco applied a finalized drawdown method to every vertical well and an additional horizontal well, which was produced with increasing choke sizes to help maximize early water recovery while maintaining the drawdown below the maximum limit. Production from the horizontal well was shown to be similar to the vertical wells, but the horizontal well’s pressure profile was significantly higher and declined at a slower rate. Exco concluded that this was because it could maintain sufficient backpressure.
Abou-Sayed said it is important, but not critical, to find an accurate bottomhole pressure when determining the maximum drawdown level.
“It’s not going to kill you immediately,” he said. “What we have seen with many companies is that they’ll have different drawdown criteria from the first week to the second week, and from the second week to the third week.”
As shale formations are fractured under local conditions, the maximum drawdown level is not measured from the initial reservoir pressure. Abou-Sayed said operators should observe reservoir pressure at three times: at the time of perforation, on the day the well is opened up to fracture, and during the first stage of production. Tighter formations often create higher pressures.
Abou-Sayed said the drop in EUR values is in part due to low effective system permeability and the design and implementation of ineffective completion and stimulation strategies. In addition, he said physical deformations sometimes cause excessive fracture conductivity loss. This leads to a lost connection between the well, the fracture, and the formation.
Another physical deformation that is of particular concern for operators is the gradual downslope movement of shale formations under the direct influence of gravity and the weight of wells and other facilities. This downslope movement, known as rock creep, can ultimately lead to a reduction in fracture conductivity.
Abou-Sayed said that creep is an important factor to consider in devising production management strategies because it is an inevitable consequence of shale operations.
“Creep will happen irrespective of what you do,” Abou-Sayed said. “You cannot stop it, but you have to live with it. The lower the pressure, or the lower the load you put into your well, the longer the creep will take before it actually hits your fracture. It’s a learning process. It’s a continuing stage.”
For Further Reading
SPE 144425 Haynesville Shale Development Program—From Vertical to Horizontal by I.S. Abou-Sayed, i-Stimulation Solutions; M.A. Sorrell, R.A. Foster, E.L. Atwood et al., Exco Resources.
DNV GL Launches Initiatives To Reduce Cost of Qualifying Composite Materials
Stephen Whitfield, Staff Writer
As offshore projects continue to grow in size and scope, the oil and gas industry is looking for new ways to lower costs. To help in that effort, DNV GL has launched a pair of initiatives focused on the use of composite components in offshore applications.
Last September, it announced the formation of a joint industry project (JIP) to investigate affordable composite components in the subsea sector. In December, the company released a recommended practice on thermoplastic composite pipes (TCP) that allows companies to use TCPs in place of steel or traditional flexible material in offshore operations.
The JIP aims to replace large-scale testing of composite components for subsea activities with a process it calls certification by simulation. The idea behind the process is to use the results from numerical simulations during qualification and certification. The JIP will attempt to validate advanced material models by experimentation, focusing primarily on predicting chemical aging.
Jan Weitzenböck, a principal engineer at DNV GL, said certification by simulation has several benefits. Operators can lower costs by reducing long-term testing. DNV GL estimated that a typical qualification campaign for a subsea composite component can cost between NOK 10 million and NOK 100 million (approximately USD 1.17–11.7 million). By adopting certification by simulation, operators can potentially save 40–50% on the certification and qualification of subsea composite components, along with an extra NOK 16 million (USD 18.9 million) in savings for the recertification of existing components.
In addition, Weitzenböck said the process can help save time requalifying and recertifying previously qualified components for new applications. It will also allow for a faster transfer of information between projects.
“Information and test results can more easily be reused in other projects, and the modeling approaches may also be applied in early design to select materials,” he said.
The JIP consists of seven companies in addition to DNV GL: Statoil, Petrobras, Petronas, Nexans, GE, Aker Subsea, and Airborne Oil and Gas. The Research Council of Norway is also funding two PhD scholarships at the Norweigan University of Science and Technology in Trondheim on this topic. Weitzenböck said the JIP members met twice in 2015 and work is well under way to delivering the first draft procedures by this summer.
DNV GL also plans to develop processes to accept mathematical material models in the certification process, which will be documented in a revised edition of the DNV GL offshore standard for composite components (Fig. 1)
The recommended practice for TCP, DNVGL-RP-F119, was developed through an 18-company JIP led by DNV GL that included polymer producers, TCP manufacturers, and operating companies. Intended to target operators, contractors, and other entities seeking acceptance to use TCP, it provides technical provisions and recommended acceptance criteria to prevent failure in response to combinations of cross-sectional forces, internal pressures, and external pressures. It accounts for case-specific issues related to use and integration when the TCP is part of a larger system and requires that a system risk assessment is performed.
Per Anker Hassel, a principal engineer of polymers, fibers, and composites at DNV GL, said TCP is a cost-effective option because it is lightweight and spoolable. This could allow operators to use smaller vessels during the installation of a pipeline or a riser and during the decommissioning phase of an offshore project.
However, companies looking to use TCP face some barriers, most of them coming from a lack of familiarity with the product and its qualification. Hassel said a barrier is that there was previously no standard to qualify TCP for offshore use. Also, despite the increased use of TCP in the last decade, the in-service experience from offshore application and installation is limited.
Hassel said traditional riser configurations might not be an optimal application for TCP risers and, because it is a more recently developed technology, companies are not used to working with it.
“As with all new technology, there is a barrier due to a lack of experience with the new technology. For example, the [TCP’s] low weight in water is a huge benefit, but it is also a challenge for deepwater riser systems with respect to dynamic behavior due to floater motions, wave, and current loading.”
For Further Reading
Torp, C. 2015. New RP on Thermoplastic Composite Pipes Offers Cost Savings. DNV GL Oil and Gas News, 14 December 2015, https://www.dnvgl.com/news/new-rp-on-thermoplastic-composite-pipes-offers-cost-savings-51433 (accessed 08 February 2016).