When CT with internal pressure is bent around the reel or guide arch, and straightened in the injector chains, it experiences both plastic and elastic deformation. This results in internal residual stresses which cause bending moments and residual curvature. A “straightener” can be used to reverse bend the CT, which causes it to be fairly straight (no significant residual bend) but it still has significant residual stresses. Residual curvature and stresses decrease the buckling load (the CT is more prone to buckling) and cause safety issues if the CT is suddenly released. They can affect the fatigue life, but they are not in themselves an indicator of the amount of fatigue damage (as some have mistakenly thought). This paper presents the concepts and equations used to determine the residual curvature and residual stresses for a sequence of bending events, axial loadings, with internal pressure. These concepts and equations are then used to demonstrate the behavior of CT for several practical situations such as when it is run in and out of a well, and when it passes through a straightener.
Accidental plug setting and stuck tools is a cause of great frustration, operational delays and ultimately deferred production. A cost-efficient and swift resolution is always desired. This paper presents a new development in engineering in the form of a hydraulic stroking tool with the ability to apply 60,000 lbs of force. The tool has already been applied in the North Sea; lessons learned from these recent operations are disclosed in this paper.
In one operation, a plug was accidentally set across the Christmas-Tree (XMT) and blowout preventer (BOP), effectively eliminating the XMT as a well barrier element and constituting a serious HSE risk. Conventional solutions failed to release the plug due to an insufficient pull force and then a failing jar.
In another well, the setting tool had malfunctioned, resulting in a partially set plug and a stuck tool. Repeated attempts with heavy duty fishing equipment had damaged the fishing neck, further complicating the fishing operation as the seting tool had failed before it could break the stud connecting to the plug.
The high performance of the recently developed stroking tool turned out to be the solution to save both of these demanding operations. In the first well, it was estimated that the force required to shear the plug from the setting tool would be 43,300 lbs. The operation was completed in three runs with no misruns, which saved the operator from prolonged exposure to HSE risk, including well control situation.
In the second well, the force required to shear the stud and free the setting tool was 40,000 lbs. Two release devices were combined in the toolstring, one below the hydraulic stroker and one below the cable head in order to allow further contingencies to mitigate risk and increase safety. After four attempts, the shear stud parted, thus completing the setting sequence and freeing the stuck setting tool. The operator got the well back on track, saved five days of rig time and avoided the costs of a workover rig.
The case stories in this paper constitute the first jobs performed with the new tool. Two important features discussed are reduced HSE risks and increased operational efficiency.
With hundreds of thousands of well stages completed in 2014, the “plug and perf” technique is the number one stimulation method used in unconventional reservoirs. This technique relies on the use of metal or composite plugs to isolate sections of the reservoir to be hydraulically fractured. After all the stimulation operations are complete, plug removal is required to enable production to begin. A motor and a mill assembly must be conveyed into the well, usually by coiled tubing, to eliminate the plugs used during the stimulation.
In wells with low reservoir pressure or long horizontal sections, plug mill-out can prove very challenging. Returns do not easily reach the surface, and fluid is often lost into the recently created fractures. Even with the use of nitrogen to assist with cleaning operations, debris from the plugs removed can accumulate in the horizontal section, posing a risk of getting the coiled tubing stuck during the operation. In addition to this significant risk, the economic impact of such operations increases under these conditions because operations tend to be lengthier and more complex than traditional plug mill-outs.
A new plug-and-perf technology has been developed to address the problems mentioned above. This method relies on degradable technology to eliminate the need to remove plugs. During fracturing, this new technology follows the same process as traditional plug and perf, but no plug removal is required after stimulation. Seat assemblies serve the function of plugs, and after all stages are completed, these seats remove themselves by simple contact with flowback water. Immediate production is possible, and the well is left with a fullbore ID. No restrictions are left in the well that would prove problematic during any future workover intervention. This restriction-free environment also allows for the full production potential of the well to be achieved, as no chokes to production are left in the well.
The operational sequence of the new fully degradable isolation assembly for plug and perforate technique have shown a seamsless integration into current best practices for Eagleford operatiors, where the technology has been applied.
In the last decade, the number of horizontal wells drilled in North America has risen dramatically. As a result, there has been an associated increase in the use of the plug and perforation system and the ball-drop system used to complete these horizontal wells. After the fracturing treatment has been completed, the bridge plugs or ball seats are subsequently milled out via the use of coiled tubing (CT).
During the plug or ball-seat milling phase, it is difficult to control weight-on-bit at the end of the CT. If the injector releases too much weight at surface, then the weight-on-bit is too high and the downhole motor can experience a stall. Alternatively, if the injector is not releasing enough weight at surface, then there is insufficient weight-on-bit to mill out the plug or ball-seat. Given that these operations are performed in horizontal wells, it is difficult to predict the optimal weight-on-bit without the presence of real-time downhole measurements.
The current data acquisition software used on CT field operations does not analyze or interpret the data - - it only records the measurements. As a result, it is an arduous process to identify trends in pressure, depth or CT string weight changes over an extended period of time. However, analyzing changes in these variables is critical for optimizing the CT milling operation.
This paper focuses on an innovative technique for analyzing real-time CT job data that can be used to calculate the required surface weight needed to achieve the optimal weight-on-bit. Furthermore, the technique also enables real -time interpretation of CT job data to confirm that the mill is making the desired progress. This technique has been implemented as a utility within a leading CT modeling software package. This paper will also present field case studies that demonstrate how the new CT interpretation utility software has optimized the milling efficiency in horizontal wells.
Rudnik, Alexander (Coil Tubing Services a Schlumberger Company) | Nava, Carlos Alberto Torres (Coil Tubing Services a Schlumberger Company) | Grunichev, Renny Alexis Ottolina (Coil Tubing Services a Schlumberger Company) | Gortmaker, Travis (Coil Tubing Services a Schlumberger Company) | Nwabuzor, Charles (Shell International Exploration & Production Company)
Coiled tubing (CT) is a well-established well intervention technique in deep water (1,001–4,999 ft [305–1,523 m] water depth) offshore environments in the Gulf of Mexico (GOM). Wells as deep as 25,000 ft [7,620 m] measured depth (MD) are routinely accessed, serviced, and abandoned with CT at the present time. However, as demand for oil and gas continues to increase, the industry is now expanding its activities into ultradeep waters (water depths greater than 5,000 ft [1,524 m]), ultradeep reservoirs (well depths greater than 30,000 ft [9,144 m]) and high pressures (maximum shut-in pressures close to 15,000 psi [100 MPa] at the seafloor and greater than 10,000 psi [69 MPa] at surface). Ultradeep water projects are becoming central to the overall deep water investments being made by the major oil & gas operators, with several projects slated for 2015.
Coiled tubing is considered one of the critical contingency operations that may be required during the completion of these ultradeep high pressure wells. CT interventions are also expected to be part of future well workover/maintenance operations. The extreme downhole and surface conditions that exist in these ultradeep high pressure wells pose many significant challenges to the CT industry, as it strives to provide safe and reliable access to these wells. In order to address some of these challenges, the CT industry has to re-evaluate various aspects of its coiled tubing design and operations, including the minimum yield stress of the pipe material, surface equipment, downhole tools, fluids, and wellbore access modeling software in order to identify any technology gaps that may affect its ability to effectively service these ultradeep, high-pressure wells. Once these gaps have been identified, they must be converted into specific action items to be addressed by all parties, ranging from service companies and equipment manufacturers to operators.
This technical feasibility study on coiled tubing deployment for an ultradeep high pressure project in the GOM describes the evaluation criteria used, identifies technology gaps and outlines the specific solutions proposed.
ICoTA Keynote Address given 24 March 2015 on Oil and Gas Industry Forecast.
Slides include information on:
Hydraulic Fracturing 2005 -2014
Hydraulic Fracturing Market
Global Oilfield Equipmentt& Services Market
Global Oilfield Market -$450b In 2014
Global Oilfield Market -$350b In 2015
Well Intervention – CT & Wireline
Coiled Tubing Services Market
Wireline Logging Market
2014 Coiled Tubing Market
Coiled Tubing Companies Ranked By Size
Coiled Tubing Market Share Over Time
Coiled Tubing $ (Millions) Per Drilling Rig
US Coiled Tubing Market
Canadian Coiled Tubing Market
Europe/Africa/CIS Coiled Tubing Market
Coiled Tubing Unit Count
Global Oilfield Since 1996
What Happens The Year After A Downturn?
Oil & Gas Industry Forecast
Edillon, Lemuel (STEP Energy Services Ltd) | McLeod, Richard (STEP Energy Services Ltd) | Henderson, Matthew A. (Fusion Technologies Inc.) | McVicar, Warren (Fusion Technologies Inc.) | Eyre, Kellen (Fusion Technologies Inc.) | Pelletier, Robbie (Fusion Technologies Inc.) | Yao, Shunyu (Fusion Technologies Inc.) | Yan, James (Fusion Technologies Inc.)
From December 2013 to February 2014, a major Canadian coiled tubing (CT) service company experienced several premature CT failures that all occurred in the same geographic region of northeastern, British Columbia. The failed CT samples were analyzed both by the manufacturer and a third party to determine the failure mechanism. Upon inspection, internal corrosion on the base material and preferential corrosion of the bias weld filler material was, in multiple cases, determined to be the cause of failure. It was concluded that microbial induced corrosion (MIC) likely caused localized corrosion and pit initiation leading to crack propagation and sudden failure.
When MIC was identified as a potential cause of failure, the service company's engineering team initiated an extensive water testing program to determine a preventative solution. The base fluid used for CT operations in the specified geographical region typically consisted of produced water, often recycled multiple times from fracturing operations. The CT service provider was not responsible for the water supply, nor did it have historical information on the supplied water quality.
In several occurrences, the fluid tested positive for the presence of harmful acid producing, and sulfate reducing bacteria, which further supported the presence of MIC. To eliminate or minimize the potential for harmful corrosive bacteria, the service company implemented a biocide water treatment program.
The service company explored several methods of applying both liquid and powdered biocide establishing a best practice for pre-treating the supplied water and treating it throughout the operation. Field testing proved the application of biocide dramatically decreased bacteria count. To date the biocide treatment program has been successful and no additional premature failures due to corrosion have been recorded. This has allowed the engineering team to optimize biocide loadings and revise the CT retirement criteria.
While the subject of microbial induced corrosion in CT has been widely discussed and published throughout industry literature, the problem has not been prevalent among CT operations in Canada. This paper discusses a specific premature CT failure due to corrosion, an analysis of the base fluid in the area that was believed to cause the corrosion, and the biocide treatment program used to prevent similar CT failures in the future.
With the current government environmental directives in the Gulf of Mexico (GoM), operators are challenged to ensure that idle iron wells are correctly handled to meet regulatory requirements in the full abandonment of the wells and their platform structures. With this, there is a need to remove existing production tubulars and set the required abandonment barriers before removing the offshore structure. Because of the current operational climate, there are many challenges that operators face in the GoM with regards to their ability to secure rig set equipment and personnel to effectively perform these operations in an economic manner.
This paper details an operational challenge of preparing for the temporary abandonment of an operator's GoM compliant tower structure, where an existing wellbore had been shut in with an annulus containing sustained casing pressure up to 3,000 psi. To facilitate the operational work scope, a hydraulic workover (HWO) rig was selected to be installed to the compliant tower structure, which allowed for the successful removal of the completion and preparation for the impending platform abandonment process, all while simultaneously working under the operational constraints of a producing facility.
This publication shows that through the application of detailed engineering and operational programming, the challenges of adapting existing equipment, restrictions on available space, reduced deck load capacity, along with crane limitations, all before HWO operations in an offshore environment with the potential for severe weather on a compliant tower, were safely overcome while performing the operations.
Clients utilizing Coiled Tubing (CT) for straddle frac operations in multi-stage horizontal wells often encounter cement stringers preventing the frac bottomhole assembly (BHA) from reaching plug back total depth (PBTD) and the packer from sealing to the casing wall. This paper presents the learnings from a >90 well campaign of preparing for fracking operations using an electric line (e-line) milling and clean-out tool. The wells were mostly cemented, 4.5? liners with frac sleeves. This technique reduced frac preparation costs in the cemented wells by approximately 30%.
The common practice in Southeast Saskatchewan (SE Sask) is to perform a “well prep” operation prior to the frac equipment's arrival to the well site. A CT unit equipped with a rotating scraper/mill—and associated fluids—is used for the clean-out, adding to the logistical coordination and well costs. Fluid has several costs associated with it: the cost of the fluid/water itself, heating for winter operations, trucking and disposal. However, “well prep” is considered “cheap insurance” by most operators working in SE Sask compared to the potential costs of a waiting frac crew.
An operator in SE Sask has had success with an alternative clean-out solution to replace the use of fluid for well preps by introducing an e-line method consisting of an electric milling & clean-out tool with a casing collar locator (CCL). The mill is conveyed by e-line tractor and is equipped with a scraper mill to confirm the PBTD and ensure that there is no cement debris or sheath present that could negatively affect the frac operation. Various bailers can be added to collect the cement debris in the same run and ensure it is removed from the wellbore.
In combination with the clean-out service, a CCL is deployed and logged to surface to pinpoint the exact sleeve location to be referenced during the frac operation. This new, efficient clean-out solution has proved slightly more time-consuming (~3-5 hours) but yielded significant cost savings of approximately 30% per well of prep costs. These savings come from using e-line equipment, eliminating fluid costs and offering inherently safer operations with a low carbon footprint.
Moreover, the paper will discuss the future applicability of this ‘additional application’ for pre-logging runs as a means to reduce total completion costs in cemented wells. This is achieved by using the e-line milling tool as a pre-run for casing inspections or cement evaluation logging.
Chevron's portfolio of subsea assets in the Gulf of Mexico is poised to more than double in the next 5 years starting with First Oil of Jack/St. Malo, the development of Buckskin Moccosin, and the expansion of its exisiting Tahiti and Blind Faith subsea development assets such as Tahiti 2 and Blind Faith 2. Subsea well recovery rates typically underperform when compared to their surface well counterparts. One significant factor is the relatively high access costs for subsea well intervention. Without frequent intervention to maintain well performance, a lot of barrels are left behind. At Blind Faith Chevron is investigating platform-based intervention alternatives that dramatically improve economics by reducing or eliminating the need for vessel-based intervention. A key enabler is the Coiled Tubing Intervention Riser (CTIR) system that creates a direct vertical access point to the flowline riser from the platform. With the flowline accessible by coiled tubing, services such as acid stimulation, artificial lift, hydrate remediation, etc. become feasible. The reach of the coiled tubing is limited to the pipeline end terminations of the riser flowlines making direct vertical access to the subsea trees still a job for the large, expensive vessels. The CTIR system does not replace the need for vessel-based intervention, but it does support some well intervention options.