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.
The use of pressure-activated toe valves in a completion string is yet another innovative approach to completing a horizontal well. This technology eliminates the need for perforating guns prior to a multi-stage hydraulic fracturing (frac) operation. Subsequently, the operator can greatly reduce costs when the need for coiled tubing (CT), wireline (WL), or workover rig (WOR) is no longer needed on location to convey perforating guns.
However, when injection rate through the toe valve is not adequate for wireline pump-down operations, or the toe valve fails to open at all, the operator must revert back to conventional methods of perforating in order to achieve injection into the well and begin the frac operation. These failures immediately negate any of the cost savings the toe valves were designed to provide. This paper will review cost effective solutions, through the use of abrasive perforating, to quickly and efficiently perforate the toe stage and minimize non-productive time (NPT).
Most often, adequate pump-down rate is not achieved through the toe valve when debris or cement is lying across the tool, preventing it from opening or plugging off the ports. Prior to perforating, a motor and bit run is common to verify that the well is clean down to plug back total depth (PBTD). This requires a minimum of two round trips with coiled tubing or a workover rig. Two different methods of abrasive perforating have been used to benefit both conventional plug and perforate and frac sleeve completions (sometimes referred to as “baffles”). Several case histories will be presented to explain how a single trip in hole, utilizing a motor BHA and abrasive perforator in tandem to clean and perforate the toe stage, can minimize costs compared to several round trips using the conventional method with perforating guns. Additionally, we will explore an innovative approach to abrasively perforate the toe stage through frac sleeves where minimal ID's pose a problem with conventional methods of perforating.
Abrasive perforating technology, in conjunction with other innovative tools, adds a wide range of flexibility for today's complex horizontal wells. Utilizing this technology, problems such as toe valve failures can be addressed in a safe and cost effective manner.
A carbonate field in the northeastern part of Saudi Arabia is undergoing major field development. 75% of the wells are extended reach wells (ERWs) or mega-reach wells. Reservoir pressure maintenance is essential, which is why peripheral water injectors and oil producers (OPs) require matrix stimulation to achieve developmental targets. The field's offshore portion contains platforms on several developed wells longer than 17,000 ft (i.e., beyond the natural reach of coiled tubing [CT]) and with an average of 6,000 ft. laterals or openhole sections. Provision of stimulation solutions for these wells drilled with mud and completed with fluids containing CaCO3 requires optimization to expeditiously complete the jobs with minimal lost time. Nonrig remedial operations are preferred compared to drilling or workover rigs, primarily for economic and technical reasons. The rigless interventions offshore present unique optimization challenges because of several surface and sub-surface complexities.
The use of a CT jackup barge with a support vessel connected by flexible hoses eliminated the need for a rig for stimulation purposes. Flexibility was crucial, such as when accommodating procedural changes for CT reservoir reach. This paper discusses the methodology, technologies and practices resulting from goals to identify cost-effective means to stimulate offshore wells to remove reservoir damage and improve well performance after drilling operations, and before putting the wells on service.
The optimized solution has allowed integrated CT (pumping, e-line, slickline) and testing services on 40 wells using large treatment fluid volumes. Customized CT stackup has resulted in improved logistics and reduced idle time between treatments. Well performance improvements up to 200% have been recorded. This translates to improved operational safety because human exposure to equipment handling is significantly minimized. The success recorded in the nonrig interventions for producers and injectors indicates that rigless CT stimulation can provide opportunities for operators to yield optimum benefits when developing a major field.
In the recent years coiled tubing (CT) has become an integral part of many well completion programs. The trend is to higher-strength CT, larger tube diameters and higher pumping pressures while employing relatively small CT spools to satisfy transportation logistics. Coiled tubing is now routinely used at stress and strain levels that significantly exceed prior experience. These conditions have identified limitations within currently available CT products. Today there is a need for higher-strength CT grades with better resistance to severe environments and better fatigue performance in both the tube body and bias weld.
A detailed study of the metallurgical basis of each production step was performed in order to understand the limitations of the current CT technology and manufacturing process. This understanding, coupled with the goal of developing new CT grades that satisfy new market demands, has resulted in a complete redesign of the CT technology and manufacturing process. Extensive trials have been performed, and a prototype manufacturing facility has been constructed to produce new tubing grades. Comprehensive mechanical testing, metallurgical evaluation, low-cycle fatigue testing, and sour (wet H2S) exposure testing of new 110 ksi and 125 ksi grades produced by the new manufacturing process were conducted. The fatigue testing was performed over a broad range of bending strain and hoop stress that anticipates severe operating conditions. Sour exposure testing included static, sulfide stress cracking (SSC) and hydrogen induced cracking (HIC) testing, as well as dynamic, low-cycle fatigue testing after sour exposure.
Laboratory and field testing of commercial-size strings has shown the fatigue life of the new CT grades exceeds the fatigue life of currently available high-strength grades. Additionally, the bias-weld fatigue life is improved significantly, both in general and relative to the base-tube fatigue life. SSC resistance of the new CT grades is considerably better than the SSC resistance of the conventional CT grades with the same strength, making it possible to increase the tubing material strength by about 20 ksi to 30 ksi without deteriorating the sour resistance.
The paper presents comprehensive information on the new CT grades, their performance in various environments under a wide range of loading conditions, as well as the qualification of the new tubing grades for field use. This allows CT operators and users to select more suitable CT grades for their applications. These new tubing grades also can enable field operations with coiled tubing that cannot be conducted safely and reliably with the currently available tubing grades.
Al-Buali, M.H. (Saudi Aramco) | Abulhamayel, Nahr (Saudi Aramco) | Leal, Jairo (Saudi Aramco) | Ayub, Mohammed (Saudi Aramco) | Driweesh, Saad (Saudi Aramco) | Molero, Nestor (Schlumberger) | Ahmed, Danish (Schlumberger) | Raza, Ali (Schlumberger) | Valley, Joseph La (Schlumberger) | Alfonzo, R.I. Ortega (Schlumberger) | Vejarano, E.R. (Schlumberger)
Scale removal in sour gas wells has been one of most challenging operations in Saudi Arabia during the last decade. Operators face particularly demanding downhole environments with temperatures above 300 °F, significant concentrations of H2S and CO2, presence of complex mixed-scale deposits with limited dissolution, and risk of H2S release and corrosion with chemical removal methods. These conditions have led to mechanical removal methods using coiled tubing (CT) as the preferred technique for well descaling operations.
During the last 5 yr, CT descaling operations have consisted of temporary formation isolation via bullhead using CaCO3 chips as a bridging agent, mechanical scale removal with CT milling and high-pressure rotary jetting tools, and abrasive perforation or matrix stimulation to enhance well productivity. Mechanical alternatives for isolation with bridge plugs are not feasible due to the presence of FeS scale in the wellbore. Wellbore configurations also require pump rates above 2.0 bbl/min to ensure suitable cleanout and transportation of solids to surface.
The recent incorporation of CT equipped with a rugged version of fiber optic telemetry and a downhole measurements package into the descaling operations workflow has enabled pumping rates above 2.0 bbl/min. Key bottomhole data has also been obtained, leading to a better understanding of the scale removal progress, optimization of downhole tool operation; reduced well intervention risk, and enhancement of overall job efficiency.
During the CT mechanical descaling stage, differential pressure across a high-pressure rotary jetting tool was kept at its optimum range of operation while maintaining slight overbalance conditions to minimize the risk of gas influx and avoid loss of circulation while removing the formation isolation. Throughout the abrasive perforating stage, real-time depth correlation saved one CT run (i.e., ±24 hr), and higher pump rates significantly reduced operation time and maximized shot size and penetration.
This paper discusses an enhanced workflow for CT descaling operations where the implementation of the real-time downhole measurements package with an enhanced working envelope resulted in a significant increase in operational efficiency, reduced risk, and optimized job performance.
This paper will outline the snubbing operations conducted to carry out a complex reabandonment in a remote jungle location.
The abandonment called for the fullbore removal of the existing cement plugs with suspected poor integrity and with uncertain pressures below. The challenge was compounded by a restricted ID in the surface equipment which was installed due to unforeseen bubbles in the 13-3/8? casing after wellhead removal during the original abandonment. The pressures observed required the use of live well intervention techniques and equipment
Several vendors for the supply of the snubbing unit were considered with focus on their stand alone capability and the availability of suitable interlock safety systems.
Due to the nature/condition of the well a number of concepts were considered to initially mill a pilot hole through the surface plug to establish communication with any pressure below the plug. As the intervention was considered urgent the primary plan was to utilise coiled tubing for this (available in country), however due to the cement plugs being inside the 13-3/8? casing it was decided to hang off a 3-1/2? conduit string from a slip ram assembly down to the surface plug to contain any CT “walk”.
Following the milling of a pilot hole, a new cement plug was to be set to act as a barrier to allow surface equipment reconfiguration to a 13-5/8? snubbing stack.
Prior to the CT being mobilised to location and whilst the snubbing unit was in transit from The Netherlands the pressure trend changed from a building trend to a stabilised pressure. As such a judgement call based on the safest and greatest chance of success was made to use the snubbing unit for all operations upon its arrival. The snubbing unit was mobilised and rigged up on to the tree to perform the initial phase of the operation of re-establishing communication to the well through a pilot hole thus allowing reconfiguration of the surface equipment. Following the reconfiguration of the surface equipment the snubbing unit was re-rigged in fullbore 13-5/8? snubbing stack mode, whereupon the reabandonment operations were conducted based on an assured programme which was amended through management of change during operations due to the wells behaviour.
The remoteness of the location required that all downhole scenarios had to be planned and equipment for all had to be prepared, tested and shipped to location. Meticulous planning was essential for this.
Post job it is evident that utilising the latest interlock systems and modular tower paid dividends in providing a safe conclusion to an uncomfortable situation.
This paper examines techniques necessary to fish coiled tubing (CT) with internal weld seams in a live well environment without back pressure valves (BPVs) using a hydraulic workover unit (HWO). The challenges of placing barriers in internal seamed CT verses using the slip and shear method is addressed.
The discussed onshore operation was completed August 2013 in North America. Using the techniques described, a 14,000-ft (4267 m) 2-in. (50.8-mm) CT fish was successfully removed from a well with an average surface pressure of 5,500 psi. This was achieved by first opening the blind rams, snubbing in, and dressing off the CT fish. Next, the CT fish was latched with an overshot and a pull test was performed, pressure was equalized, and the slip and pipe rams were opened. Following, the CT fish was picked up and moved to a desired location in the blowout preventer (BOP) stack (approximately 51 ft 4 in.). The slip rams were then closed and a weight check was performed. The pipe rams and inverted rams were then closed. The CT fish was shear/cut, the pipe was picked up and the blind rams were closed. This was concluded by laying down the fish and the process was repeated 276 times with an average cut of 50 ft. The HWO fishing procedures consisted of 541 hours without any health, safety, or environment (HSE) incidents, accidents, injuries, or job failures.
Electric wireline tractor conveyance technology was introduced to Statoil operations in Norway in the mid 1990's. Uptake was rapid and the technology offerings expanded to include ‘powered mechanical’ services run in conjunction with wireline tractor conveyance – further development and expansion of these services is on-going. This development is to a large extent reflected in global oilfield operations with widespread acceptance and application of these technologies.
Since 2008 a detailed record has been maintained of wireline tractor operations and runs for Statoil operations. This database is used to rapidly identify reference operations for on-going activities but also serves as a source of statistical information useful for strategic planning. The database is currently populated with information on over 900 separate wireline tractor operations and over 3000 individual runs – the vast majority of the data is from operations in Norway with some additional activity in Brazil and on US land operations.
There is a large, and growing, collection of technical papers addressing the technology and operations related to wireline tractor and related services. Most of these publications refer to specific technology descriptions and individual, or collected, case histories. With the aforementioned database of information we believe that there is a good basis for providing a more ‘holistic’ review of the results of applyling tractor and related technology – at least within the context of Statoil drilling and well operations in Norway.
This paper will:
Discuss the introduction and uptake of tractor related services within the historical context of Statoil operations in Norway.
Provide context in terms of the reservoir, well and operational environments encountered on Statoil operations in Norway.
Provide a statistical overview of the applications of wireline tractors and related technologies for Statoil in Norway.
Discuss the success rate of various applications of the technology within the context of Statoil operations in Norway.
Discuss future challenges and opportunities.