This paper will discuss the development of abrasive cutting technology deployed via coiled tubing for cutting production tubing, drill pipe, drill collars, exotic stainless steel completion components, single strings of casing and multiple strings of casing.This technology is performed utilizing a sealed bearing, positive displacement motor and a cutting head along with conventional coiled tubing tools and conventional coiled tubing.This technology gives operators an additional tool when severing of the drill string or production tubing is required.
Additionally the paper will discuss perforating tubing and casing using abrasives, particularly in horizontal wells where conventional wire-line operations are not possible.
The paper will discuss:
Utilizing a positive displacement motor to perform abrasive cuts via coiled tubing,
Design and testing phases of the abrasive cutting system,
Initial field runs to prove the viability of this technology,
Total jobs completed to date,
Lessons learned throughout the process,
Where this technology leads from here.
The paper will also discuss future applications for this technology which include cutting casing for plug and abandonment programs, permanent packer retrieval, and abrasive perforating all deployed via coiled tubing.
Coiled Tubing operations in the North Sea are regularlychallenged by crane lift capacity limitations when attemptingto bring coiled tubing reels onboard. Very often the cranecapacity or weather conditions determine the CT size to beused for the application, leading to operations conducted withless then the optimum CT size. The Norwegian sectorgenerally has larger capacity cranes but most operationsregularly involve the use of large OD coiled tubing (2.375" or2.875"). The lengths required can cause logistical problemsdue to the lifting weights of the CT reels used. Currentmethods utilised for keeping weights as low as possibleinvolve using so called split reel systems and thin-walled highstrength parallel CT strings (i.e. constant wall thickness).While these weight reducing measures have proventhemselves for many years now in the Norwegian sector, theycan not resolve equipment weight issues in all cases. Thejoining of 2 or more separate strings together offshore byinstalling butt welds has been standard practice in the UKsector for many years now, mainly involving CT sizes of up to1.75". In the Norwegian sector, butt-weld failures haveoccurred when using larger CT sizes and operators have beenseeking a viable option to butt-welding, especially for larger OD CT.
In response to a direct request by the BJ Services North Seaoperations departments, BJ Services Coiled Tubing Research& Engineering group in Calgary, Canada have developed andcommercialised a LCF (Low Cycle Fatigue) SpoolableConnector to replace offshore butt-welding and resolve weightissues associated with heavy CT reels.
Achieving effective stimulation across zones not readily accessible is a common challenge in the oilfield. Several authors[1-3] have presented case histories in which horizontal wells completed with slotted liner, gravel pack, internal gravel pack, or plain sand screens were difficult to stimulate because there was no easy way to effectively remove drilling fluid filter cake from the wellbore walls. Similar inaccessibility is encountered when dealing with straddled completions, where out of necessity, the producing zone is placed behind straddle packers that are extremely challenging to reach. Another accessibility problem is encountered when a "fish" becomes caught up across the perforated interval and accessibility is again denied.
Should such wells produce trouble-free and meet expectations, there is not much to ponder; but if not, the options for executing an enhanced stimulation treatment have been limited. Generally, treatment has consisted of pumping and squeezing away the treatment into the perforations and hoping for the best. The preferred technique is to improve the injectivity into the perforations by "spotting" reactive fluids at the perforations or using some type of mechanical action such as "perforation jetting" to break up blockages in the perforation tunnels. This is only possible when perforations or pays are accessible through the wellbore.
These problems become more complicated if the zones of interest are sandstone reservoirs. A study in the late 1990s revealed a success ratio in the 30-40% range when treating such formations.
This paper primarily deals with a case history in which a sandstone reservoir, not previously matrix-acidized, was producing at sub-par rates, eventually declining to a negligible production status. The zones were completed between straddle packers and were only accessible through a sliding side door (SSD), 100 ft above the perforations.
The prudent decision was to stimulate, but make all efforts to maximize the chances of success. Apart from applying the best practices in sandstone acidizing technology, a true fluidic oscillator (TFO) was included as a stimulation tool. This tool provides a continuous pressure pulse in the fluid system that allows solids buildup within the perforations to fatigue and break up while the acid system works on the rock matrix.
The results from the treatment of this well were exceptional and will be detailed in this paper. The production improvement was 10-fold over its prestimulation performance.
Well X was an exploration well drilled in the Badr El Din field of the Western Desert of Egypt (Fig. 1). Original plans were to target a deep formation (lower Cretaceous), in addition to evaluating the upper Cretaceous reservoirs (Fig. 2). The openhole logs contained a few surprises: (1) the deep zone was found to be water-bearing and therefore was plugged back, (2) Sands A and B were found to be oil-bearing and at virgin pressure (5,350 psi), and (3) Sand C was gas-bearing with a depleted reservoir pressure (2,500 psi).
The well therefore required a selective completion to isolate Sands A and B oil zones from the Sand C gas. A straddle packer with an SSD allowed separation of the oil-producing zones (to be commingled) from the gas zone that would be produced through the main production tubing (Fig. 3).
The oil zones were perforated first, producing at an initial rate of 450 BOPD. The production rate declined fast, reaching 200 BOPD and finally ceased to flow within three months (Fig. 4).
Crude produced in the North of Monagas Estate, East Venezuela, has a high asphaltene content, which comes out of solution in both the wellbore tubulars and pipeline. This can eventually lead to complete plugging of the pipeline. This increases the cost of maintaining production because of the need to periodically remove these organic deposits. In a specific case, 9 km of 8-5/8-in. outside diameter (OD) production pipeline was successfully cleaned out using 2-in. OD coiled-tubing (CT) to regain pipeline production. As there is limited literature or documentation on the use of CT for this specific application, the operator and the service company established a joint team to do the feasibility study and engineering. Some of the key points were; the design of a frame to lay down the injector head, define the entry points along the pipeline, the selection of the bottomhole assembly (BHA), and fluids to use. Other issues were the measurement of stresses (push/pull) on the CT so that the CT could be run as far as possible in the pipeline without damaging either the CT or the pipeline. The pipeline was successfully cleaned, the CT being run seven times from five different entry points in the pipeline. This resulted in savings of USD 1 million for the operator and significantly reduced the time to recover normal production in the pipeline.
The characteristic asphaltene content in the crude produced from the northeastern Venezuelan oilfields,1 requires periodic CT cleanouts with solvents and mechanical means to remove the obstructions that plug the wells and reduce production. These asphaltenes precipitate from solution in the wellbore tubular, caused by the pressure and temperature differentials, and progressively reduce the flow area in the tubing. Surface facilities are not exempt from this phenomenon. As the crude flows through the pipeline, the asphaltenes settle at the bottom due to the lower temperatures and pressures in the system.To prevent total plugging, the operators pump solvent mixtures and pigs through the pipelines, however without regular treatments the pipelines become restricted and eventually the production rate drops.
In the case studied, this phenomenon led to an increase in the differential pressure in the line and ended in complete production stoppage on the surface system. This forced the operator to look for alternative means to reestablish and maintain production. Fig. 1 illustrates the progressive increase in the pipeline's differential pressure caused by the asphaltenes accumulation. Conventional pipeline maintenance practices could not be performed. Pumping aromatic solvents was not an option given the environmental constraints.
Temporary Production Assisted by a Mobile Testing Unit
To maintain the well's production, a program designed to produce the well using a mobile testing unit (MTU) was implemented. A choke manifold, a flare, two separators, and twelve 500-bbl capacity storage tanks were connected to the well and reconnected to the production line. Because of the severity of the pipeline plugging, it was necessary to transport the produced oil using trucks, increasing the risk associated with human error and environmental incidents. Fig. 2 illustrates the MTU layout.
An attempt was performed to unplug an entire pipeline section, with the assumption that the plugged section would be below the river crossed by the pipeline, as this was the coldest and the lowest point in the pipeline. Two pipeline entry points (HT1 and HT2) were constructed to perform a first test across the river section by pumping water at a maximum pressure of 2,900 psi. Different pipeline sections were tested following the same procedure. When the pressure built up and there was no resultant flow at the other end, a plugged section was identified. Two main plugged sections were identified. The results showed that these plugged sections were located between the pipeline entry points HT3 and HT2 and between HT1 and HT4. Fig. 3 illustrates the pipeline layout on the field and the pipeline entry point locations.
Coiled tubing (CT) is widely associated with underbalanced drilling technologies. Especially in depleted reservoirs, drilling need for underbalanced and extended reach wells is increased where CT is widely used. In this work, optimization of volumetric requirements for liquid and gas phases is investigated in long horizontal and inclined sections of CT applications for underbalanced drilling. A mathematical model is introduced in order to predict the flow characteristics of multiphase flow through an annulus. Flow patterns and frictional pressure losses are evaluated using the experimental data of a wide range of liquid and gas flow rates recorded at a field-scale annular flow loop with common CT drilling dimensions as well as circular pipes. Practical curves are developed for determining the optimum flow rate combinations for CT applications using the developed model. A sensitivity analysis is also conducted on underbalanced and CT drilling parameters on pressure drop and flow patterns.
The standard well-completion method in the Valhall field has evolved since 1996 to include multiple proppant fractures along the horizontal laterals. Coiled tubing (CT) has been used since then to perform over 200 post-fracture proppant cleanout operations. Field practices were developed from these jobs but the process in different stages of proppant cleanout operations had not been systematically optimized to realize best performance until the launch of a new process to optimize CT proppant cleanouts.
In May 2004, a study of proppant cleanout process optimization was completed by analyzing historical cleanout performance and incorporation of a new, integrated wellbore-cleanout system to improve operational efficiency through optimized processes, improve safety and reliability by implementing standardized procedures, and reduce stuck-pipe potential through improved design. This study analyzed the whole process of proppant cleanout, captured best practices through validation of field experience, introduced innovations to routine operations, and engineered a new, more efficient cleanout procedure for field operations.
The field implementation of this new process optimization on the first three wells, a total of 22 zones, indicated a significant performance improvement. The optimized process saved a total of 6 days' working time and encountered zero incidents that might have led to stuck pipe. The new cleanout procedure was followed by different operational crews on the job and has been adopted as a best practice for future wells.
This paper details the engineering and implementation of CT post-fracture proppant cleanout process optimization in the Valhall field and demonstrates a step-change improvement in Valhall CT cleanout performance during the past 9 years.
Drilling and workover rigs use a drawworks to pull up on the tubulars deployed into a well. The drawworks is attached to a mast or derrick, which in turn is supported by the ground or a floating vessel. The tubular's weight is not transferred to the wellhead.
Coiled Tubing uses an injector head, instead of a drawworks, to pull and push tubing in and out of a well. The injector is generally mounted directly onto the wellhead, unavoidably transferring some of the reactive loads to the wellhead.
These loads can be very substantial. They not only include the tubing's weight in the well but also loads generated by the Coiled Tubing on surface, that tubing which is being bent and pulled sideways. Often additional support is required to at least partially isolate these loads from the wellhead. This paper identifies the various loads that Coiled Tubing imparts to a wellhead and how support mechanisms provide protection to the wellhead.
Increased production and lower costs in shallow gas wells are closely linked to developing and refining new coiled-tubing drilling, completion, and production techniques. Innovations in coiled tubing have reduced the costs of drilling and completing these wells and increased their productivity and life cycles. Coiled-tubing fracturing is one such innovation. This has been used for some time now, predominantly in North American shallow gas wells. In these wells, the cost advantages associated with working over the well in a live condition while reducing job time are attractive.
Coiled-tubing fracturing operations usually employ straddle-type tool configurations. However, with a typical maximum lubricator length of about 30 ft, straddle interval lengths have been restricted, which increases the amount of resets required to effectively fracture individual zones. This restriction also increases the potential risk of communication above the assembly.
This paper describes the development of an economical and reliable coiled-tubing fracturing system that allows selective fracturing of previously bypassed pay zones. This is now possible because the system can be conveyed in a tandem configuration that works within current lubricator restrictions, but is capable of setting repeatedly as a retrievable bridge plug and treating packer combination. This allows longer zones to be precisely isolated multiple times in a single trip in hole.
This innovative technique can not only reduce intervention costs but also reduce the total time required to complete the operation. This paper will examine several case histories, with emphasis on pre-job planning, equipment selection, well site execution and post-job results.
This paper describes the results obtained, the techniques used, and the challenges involved in providing a water shutoff solution to a subsea gas production well with a sand screen completion on the Rose field in the UK Southern North Sea.
The project began with a detailed reservoir analysis to determine if intervention was practical in this subhydrostatic well. This led to the planning and sourcing of suitable coiled tubing (CT) and pumping equipment, as well as an associated zonal isolation chemical solution.
The design of the intervention was tailored to operate within the environment of a jackup installation located over a subsea well. This included CT and fluid pumping operations. The basis of the technique was to shut off the water-producing interval in the horizontal completion and isolate the unsupported annulus between the water bearing and gas producing intervals. The greatest challenge was to isolate the horizontal annulus between the gas and water producing zones. This required setting of mechanical barriers and the placement of suitable zonal isolation material that would set quickly without slumping and leaving the top of the annulus unsealed. This paper details the lessons learned throughout the intervention.
In the case of the Rose well, it now produces dry gas. This was the first time globally that this technique had been applied to a subsea horizontal well.
As in many oil fields, the primary coiled-tubing (CT) operation in the Kuparuk River Unit on the North Slope of Alaska is a wellbore cleanout. These cleanouts remove produced fines, fracturing sands, scales, and paraffin. As drilling technology advances and wells become longer and more deviated, the process required to clean out these highly deviated wells becomes more complicated. One such case, West Sak Well, is an undulating horizontal well in unconsolidated West Sak sands with a low bottomhole pressure (BHP). During previous attempts with standard cleanout methods, returns were lost during the job and the final results were less than optimal. Post-job reviews of the unsuccessful conventional cleanouts illustrated where previous approaches were insufficient.
This paper describes the use of an integrated cleanout system that efficiently addressed all the challenges of the West Sak Well, which resulted in a successful cleanout returning the well to production. This integrated system approach to wellbore cleanouts was recently commercialized, and this well was the first job using the system in Alaska.