Many advancements in completion technology have emerged to increase productivity and reduce break-even costs, but the best solution depends on development.
Since the first hydraulic fracturing test in 1947, millions of fracturing operations have been performed in vertical and horizontal wells around the world. 1 However, more than 70 years later, there has not yet been a single, perfect formula for increasing production and maximizing production.
Annual reports, investor presentations, and keynote speeches often boast about the latest methods or technologies that will drive the ultimate recovery. Some of these strategies are very different from the available strategies, while others include slight modifications to common deployments. Although each iteration combines past experience and lessons, the biggest lesson may be that there is no one-size-fits-all solution-the best completion method to maximize production is a flexible method.
Deploying the right completion system for a specific well or development means having the flexibility to choose a method that takes into account specific reservoir or regional differences, and then make adjustments to maximize the return on investment.
Due to the proliferation of horizontal wells and multi-stage stimulation over the past two decades, the number of adjustments to completion strategies available to producers has grown exponentially. Some considerations include making a decision between open hole or cement wellbore, performing single-point or limited-access stimulation, and deploying a plug-and-play or sliding sleeve system. In these high-level consideration areas, there are several adjustable tools and solutions that provide flexibility to adapt to completion trends. Some common completion trends in recent years are:
Here, we will explore some completion options related to each of these trends that can help operators optimize production enhancement plans and maximize their assets.
In the past five years, the number of horizontal wells with lateral lengths exceeding 10,000 feet in unconventional oil fields in the United States has increased significantly, as shown in Figure 1.
Although longer branch pipes provide operators with greater reservoir coverage, they are not without challenges. A special challenge is to effectively stimulate the tip of the well. Operational challenges and risks arise when using tubing transport perforation (TCP) in the first stage of a completion operation, simply due to the nature of the extreme distance that the tool must travel down the well. Generating enough weight-on-bit to grind tools, after stimulation, is another challenge that may arise when completing large-scale lateral operations.
Advances in hydraulically activated toe joints (Figure 2) have been developed to meet these challenges and eliminate the need to run coiled tubing deployment tools at the deepest stage of the well.
The simplest solution enables manufacturers to deploy plugs through cables instead of coiled tubing for the first stage of plug and piercing operations. The wet shoe joint is a hydraulically activated tool that runs just above the floating ring and is activated by a landing dart to establish contact with the reservoir and start stimulation operations. The rupture disc connector is also a hydraulically activated tool, without the need to run coiled tubing to perforate the first stage of the plug hole completion, but it is usually operated as an economical alternative to the main hydraulic toe casing. If necessary, the rupture disc will burst at a set pressure to establish communication with the reservoir, thereby enabling a cable tool to be deployed to stimulate the first stage or to evacuate the ball to move the first casing.
At the same time, hydraulic toe sleeves can increase production in the first stage without deploying any downhole tools. These injection/production ports are opened using hydraulic pressure and create a path for the first stage of stimulation. A version that can pressure test the casing string before activation is also available to meet the integrity testing requirements of certain jurisdictions.
Combining hydraulically activated toe joints with sliding sleeve technology at the lower stage of the extended reach side well can further improve the operating efficiency of the first stage. In particular, the ball-driven sliding sleeve allows the operator to start the process more flexibly and faster, and eliminates the need for milling at the toe of the arm side branch.
The trend of pumping at a higher rate to increase production, with high fluid volume, higher proppant load, tighter stage spacing and higher number of stages, helps to improve operational efficiency and higher output, Figure 3.
However, the same proppant that increases production—especially at high production—can also corrode downhole tools to the point of failure, leading to expensive remedial solutions or reduced production, and possibly both.
In plugging and perforation completions, proppant erosion and expanded perforation cause the first cluster to receive most of the fluid, while other clusters in the same interval receive the least or no treatment. In a ball-driven sliding sleeve system, the turbulence of fluid flowing through the valve seat causes a slight increase in pressure. This is not important for a seat, but a completion string of 40 to 50 sliding sleeves adds thousands of pounds of additional frictional pressure, which is the source of operational problems. Fortunately, by reducing fluid friction and reducing ball/seat and entry point erosion, these problems have been alleviated specifically for single-point and limited entry completions.
The sliding sleeve has been redesigned to reduce accumulated fluid friction. Using computational fluid dynamics simulations, the reshaping of the internal fluid path reduces the pressure drop (and fluid friction) by more than 60%, Figure 4.
These design improvements have been implemented throughout the Packers Plus product line and have reduced the number of stages by allowing smaller seat increments in the StackFRAC HD-X multistage system and TREX limited entry and single point entry systems Obstacles.
Production logging also shows that only 20% to 50% of the expected fracturing targets in the perforation group are produced at the fracture stimulation rate. 3 This inefficient use of proppant leads to lower than expected yields and lower return on investment. The TREX limited access system uses a single drive ball to pass through multiple QuickPORT IV sleeves. These sleeves have also been redesigned with 40% fewer moving parts than the previous version, reducing the risk of failure due to sand accumulation or erosion.
The nozzle on the QuickPORT IV casing is reinforced with tungsten carbide, which virtually eliminates the erosion of the entry point during stimulation. The offset spacing of the nozzles is conducive to the uniform distribution of the treatment of the entire entry point.
At the turn of the century, the single digit series in the early stage of multi-stage stimulation has given way to the usual 50-stage pumping operation, and the experiments on wells above 100-stage have become more frequent. Although this growth allows producers to use more reservoirs in each wellbore, the time and costs associated with milling actuation balls or plugs in sliding sleeve systems and fracturing plugs in perforation systems are also Synchronous growth.
The ball valve sleeve completely changed the completion operation through continuous pumping operations. The time and cost reduction benefits associated with continuous pumping operations in single-point entry ball-driven sliding sleeves were quickly adjusted to allow one ball to open multiple sleeves in one stage-mimicking the limited entry of plug-and-play deal with. These systems were soon further developed for cementing liner completions.
In order to supplement the reduced operating time during the increase in production, the degradable ball technology is matched with the ball-driven sliding sleeve system to eliminate the need for milling the system and reduce the time to mill the ball seat when needed.
Later, a variant of the sliding sleeve completion system was developed to provide a complete inner diameter in the wellbore after stimulation and eliminate rolling. The sliding sleeve completion system is activated by a shift tool and runs on coiled tubing, which is one of these changes. These systems can complete a large number of stages, only limited by the range of coiled tubing, and usually use a packer on a shift tool to activate the casing, and then provide isolation for each stage during stimulation.
The Packers Plus Quadrant system has recently been redesigned with no packer elements on the mobile tools to simplify operation and minimize the risk of tool jams. The closable function of the Quadrant sleeve reduces operational risk by opening subsequent stages after closing the previous stimulation stage. This function can also be used as a mechanism for fluid transfer and stimulation.
Although the ball and CT activation system enables operators to reduce completion time and costs, plug-and-play completion is still the main completion method. One disadvantage of plug hole completion is the time and cost required to grind out the fracturing plug from each stage before production. Early fracturing plug innovations focused on shortening the plug and incorporating composite materials to speed up the milling speed and produce fewer and finer debris. Further improvements in material science soon led to a completely degradable plug to completely eliminate grinding out, Figure 5.
In the past 20 years, as operators continue to develop new oilfields, maximize recovery rates, and increase the number of stages and processing scales, well completion technologies have continued to evolve to meet the needs of operators.
Nearly 20 years ago, sliding sleeve technology helped complete the revolution in the completion industry, and has been steadily innovating over the years to help maximize efficiency. From ball-driven sliding casing to cementing casing and coiled tubing-driven casing, each evolution has played a role in improving the completion capacity by handling longer side wells, more stages, and more proppants and fluids. It worked. Similarly, over the years, materials science has helped improve the performance of fracturing plugs, and each technological iteration provides manufacturers with another option to develop assets, depending on the best technology identified as the asset.
These technological changes and options provide manufacturers with the flexibility to develop their specific geology and take into account completion trends such as wide-scale sidewells, high-speed production increases, and reduction or elimination of grinding. fertile
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