The past two decades have seen impressive advances in drilling and completion technologies, allowing E&P companies to extract oil and gas from deep, tight reservoirs that conventional wisdom considered economically off-limits. In North America, for example, the growing development of unconventional shale reservoirs has necessitated the development of longer horizontal (3,049 m [10,000 ft] and beyond) and extended-reach wells.

As the length of these lateral wells grows, so does the need for new stimulation and intervention techniques. Coiled tubing (CT) is commonly deployed as part of the plug-and-perf method of hydraulic stimulation to run tubing-conveyed perforating guns ahead of fracture stimulation and then to deploy a mill or bit to remove plugs.

The farther that CT is deployed in a well, the greater the frictional effects build up to counter the tubing’s forward progress to target depth (TD). Unless these downhole frictional effects are minimized, the CT can lock up well short of TD.

The service industry has spent considerable effort to develop technologies that lower the coefficient of friction between the CT string and the wellbore. Simply increasing the CT diameter to improve lateral reach may work in theory but presents logistical challenges in the field. Solutions such as vibrating tools, conveyance tools (tractors) and lubricants are commonly used but poorly understood. Operators often experience a lack of consistency in results from well to well and poor correlations between laboratory tests and field results.

general well schematic

FIGURE 1. This general well schematic shows the predicted and actual CT lock-up points and the deployment improvement that the EasyReach fluid hammer tool provided. (Source: Baker Hughes)

Back to basics

Baker Hughes embarked on a research project to understand downhole frictional effects so deployment technologies could be designed to minimize friction and reach TD.

The first part of the project investigated the design and function of a fluid hammer tool in CT operations. This tool employs a fluidic switch that activates a piston in the tool. The back-and-forth movement of the piston generates regular pressure pulses, which subsequently create vibrations in the CT that overcome the static friction regime between the CT and wellbore. This allows the CT to advance more easily along the lateral.

The research focused on gaining a better understanding of the relationship between fluid hammer pulses and the axial and radial vibrations generated. A numerical model was developed to simulate the fluid hammer pulses and the subsequent axial and radial vibrations of the CT string. The model factored in the CT size and metallurgy, hammer tool parameters (size and valve frequency), pumping rate, and downhole pressure.

For operational parameters chosen in this study, the model indicated that axial vibrations were the predominant driver for pulling the CT string toward TD. However, radial vibrations helped keep the CT in a dynamic state, providing a higher dynamic coefficient of friction that lowered overall friction between the CT and wellbore.

This research helped the service company develop better deployment options for its EasyReach fluid hammer tool. This was particularly helpful for an operator in western Kazakhstan, which was looking to convert existing vertical wells to horizontal producers. Conventional CT deployment proved ineffective in covering the entire 1,200-m (3,937-ft) horizontal section as frictional forces caused the CT to lock up before it reached TD of 6,492 m (21,300 ft).

The company’s CIRCA CT modeling software predicted lock-up at 6,234 m (20,453 ft), and after the CT string was deployed, lock-up actually occurred at 6,312 m (20,709 ft). Once activated, the fluid hammer tool allowed the CT to reach TD (Figure 1). The operator was able to mill out a ball and acid-stimulate the reservoir section that could not be reached with a standard CT bottomhole assembly.

case history for new lubricant

FIGURE 2. Case history for new lubricant shows predicted and actual weight gauge curves during running in hole, or RIH, and pulling out of hole, or POOH (coefficient of friction = 0.22 and 0.13, when no lubricant and the fluid hammer tool were used and then when the lubricant and the fluid hammer tool were used, respectively). (Source: Baker Hughes)

Building better lubricants

The coefficient of friction reductions achieved through the hammer tool studies would fall short of getting the CT string to TD in extremely long laterals (6,096 m [20,000 ft] or longer). This prompted a closer look at lubricants, which have historically provided a 15% to 20% reduction in the coefficient of friction from a generic 0.24 (without lubricant) to 0.19 (with lubricant).

These field results compare poorly with laboratory tests run in traditional high-pressure rotational friction instruments. Downhole coefficients of friction may be an order of magnitude higher than values obtained in the lab—a difference that might result in the CT string being 1,524 m to 1,829 m (5,000 ft to 6,000 ft) short of reaching TD.

The company believes that a lubricant’s field performance depends on parameters that have never been accounted for in lab tests. These include downhole temperature and pressure, roughness of the surfaces in contact, metallurgy of the CT, weight on bit, well length and inclination, and chemistry/composition of the reservoir fluids.

These parameters were inputs to the software, which provided estimates of the length or depth that the CT string can reach at a given weight gauge reading and when lubricants will be required to prevent lock-up. The estimates obtained from a set of downhole conditions were corroborated with a laboratory linear friction-testing instrument designed to better mimic downhole conditions such as linear sliding and light contact pressure.

To date, the company has conducted more than 6,600 measurements with this system using various combinations of lubricants, base fluids (brines, freshwater, seawater and produced water), fluid friction reducers, various temperatures and pressures (up to 150 C [302 F] and 12,000 psi, respectively), and CT and casing samples of different metallurgy and roughness. This extensive testing was instrumental in the development of a new lubricant that provided a coefficient of friction of approximately 0.13, which was confirmed in West Texas field tests in late 2013. The new water-based lubricant is compatible with seawater, freshwater and produced water systems; has a low hazard profile; and is approved for use in the North Sea.

These parameters were particularly important for a North America operator with a well in the Permian Basin containing a 1,555-m (5,100-ft) lateral with the majority of the inclination in the 89? to 93? range. This operation was to perform an annular fracture treatment with diversion achieved by using a CT-deployed packer. First runs with the fluid hammer tool produced a coefficient of friction of 0.22 with 1,000 pounds force tensile force. This slightly lower coefficient of friction (0.22 vs. 0.24 default value) was attributed to the vibrations of the fluid hammer tool.

While running the CT for packer deployment and fracture treatment, the new lubricant was introduced at a concentration of 1% of the total fluid volume with a pump rate of 0.75 bbl/min. This assured that a thin film of lubricant was uniformly distributed in the lateral. In addition to the lubricant, friction reducer was added at 0.01% for fluid frictional pressure reduction. Both lubricant and friction reducer were circulated via constant rate chemical additive pumps to remove any human errors during mixing.

Post-job force matching in CIRCA revealed coefficients of friction in the lateral of 0.13, a friction reduction of 41% and 46% compared to the cases when no lubricant and the fluid hammer tool were used and when no lubricant and no fluid hammer tool were used, respectively. Weight matching results for running in hole (RIH) and pulling out of hole (POOH) are shown in Figure 2.

The back-to-basics research approach developed testing protocols that provide closer confirmation between field trials and lab results and allowed the service company to fine-tune its fluid hammer tool, simulation software and lubricant chemistry, achieving consistent reductions in downhole coefficients of friction of between 40% and 60%—effectively doubling the deployment length.