Well stimulation is an effective technique for removing wellbore damage, or “skin,” and restoring a well’s productivity or injectivity. Dynamic fluid pulsation is a proven approach for placing fluids during well stimulation or IOR activities where conventional approaches have proven to be ineffective or marginally beneficial.
While dynamic fluid pulsing is not new to the oil and gas industry, the phenomena of dynamic fluid pulsing and its benefits do not fall within the conventional view of porous media mechanics. The origins of dynamic fluid pulsing date back to the late 1990s, and the technique has been the subject of a wide range of academic studies as well as numerous patents on the process and tools associated with the technique.
The economic and production/injection benefits of dynamic fluid pulsation are related to the application of long-wavelength displacement waves that bring dynamic energy to fluids at the pore scale, overcoming flow barriers and dispersing fluids deeper and more uniformly throughout the reservoir matrix.
Dynamic fluid pulsing also has been used extensively in waterflooding applications to improve sweep efficiency, reduce water cut and ultimately improve oil recovery. More recently, an intensive effort has been made to move fluid pulsing technology from the longer- term applications of permanently installed tools for IOR purposes to shorter-term applications such as coiled tubing matrix stimulation.
All oil reservoir rock is more or less heterogeneous at all scales of micro, mega and pore. Heterogeneity refers to the geological complexity of a reservoir and the relationship of that complexity to the flow of fluids through it. Generally, the higher the level of reservoir heterogeneity, the more difficult it becomes to achieve maximum fluid distribution or conformance. Improving conformance in a non-homogenous material, such as an oilfield reservoir, means improving flow through lower permeability regions. During a well stimulation using a treatment fluid, such as acid, the goal is to move the acid through the entire rock volume. The physical constraints of fluid flow negatively impact that ideal outcome in two ways.
First, injecting a low-viscosity fluid like acid into a higher viscosity fluid like oil results in the formation of viscous instabilities, or “fingering.” Second, because of heterogeneity, fluid flow will concentrate in the higher permeability zones (i.e., the path of least resistance) leaving the lower permeability zones virtually unswept by the injected fluid.
Stimulations are accomplished through a variety of techniques but most commonly by injecting chemicals to treat existing conditions in the reservoir.
The use of chemicals in treating wells is more effective when the fluids are placed along the completed interval with maximum distribution and depth of penetration. Conventional steady-state injection methods are limited in their effectiveness for this operation. Without the aid of mechanical or chemical diversion, the latter which may lead to reservoir damage, such formation characteristics reduce treatment effectiveness as the chemicals merely follow existing flow pathways.
Dynamic fluid pulsation versus other conventional methods
Dynamic fluid pulsing works effectively as a reservoir stimulation method primarily because it forces injection fluids outside the path of least resistance through a dispersion process. The waveform associated with a purpose-created fluid pulse has a saw-tooth shape, which provides several benefits over traditional stimulation methods. The sharp change in pressure in a very short period directs flow radially into the formation, inducing fluid dispersion, which includes deeper penetration and more uniform distribution of treatment fluids, and has shown to overcome difficult reservoir conditions. However, the difference in pressure is only a small piece of the puzzle. How the change in pressure is created is a key characteristic of dynamic fluid pulsing versus acoustic, sonic and jetting approaches and ultimately the reason for fluid dispersion into the reservoir.
Dynamic fluid pulses are highly effective as a fluid placement technique for a variety of reasons:
• The pressure gradients involved in the normal flow of fluids through the reservoir are generally very small when viewed at the pore scale, yet small differences between these pressure gradients determine the path of least resistance that governs the normal flow of fluids. Typical amplitudes associated with dynamic fluid pulsing alter local pressure gradients and completely dwarf those associated with normal fluid flow in the reservoir, causing accurate fluid placement throughout the entire interval even through zones of high resistance to flow;
• Dynamic fluid pulsing forces fluid into the spaces between the grains of rock or sand, which causes a very small and completely harmless expansion and contraction of this pore space, thereby giving rise to an improved dynamic permeability;
• The increase in dynamic permeability and the fluid displacement pulses allow fluids to travel more uniformly through the reservoir; and
• The typical radius of influence (as penetration depth depends on porosity, permeability and the volume of fluid injected at a single point) of the dynamically placed treatment fluid can approach 1 m (3 ft) or more.
Like kinking a garden hose, precise amounts of energy are repeatedly built up and released by the tool. The pulses add acceleration and momentum to the injected fluid, forcing it into the reservoir’s nooks and crannies and more impermeable rock at speeds of up to 100 m/s (328 ft/s). (Source: Wavefront Technology Solutions Inc.)
A two-step process
Dynamic fluid pulse stimulation is a two-step process. Step 1 is a wellbore cleaning process to remove any scale or flow impediments within the wellbore using a cavitation-based pulsing tool that creates a water hammering effect to remove debris. Step 2 is the main treatment and employs a magnetic- based flow-driven device that operates entirely on a pressure differential where the opening and closing of a downward shifting piston allows fluid to exit the tool at high acceleration.
Why a two-step process? While the pressure differential flow-driven method works effectively as a way to force injection fluids outside of the path of least resistance and deep into the reservoir, it is not well-suited to scale and fill removal because the energy generated by the tool is that of a high-amplitude, low-frequency sawtooth wave. In contrast, devices that generate higher frequencies and lower amplitudes having a sinusoidal waveform (or continuous wave) are more suited to the removal of scale. A cavitation-based, acoustic pulsing tool is used to remove material from the wellbore and near wellbore region to prepare the well and formation for matrix stimulation via the pressure differential flow-driven device.
Have a story idea for Operator Solutions? This feature highlights technologies and techniques that are helping upstream operators overcome their challenges. Submit your story ideas to Group Managing Editor Jo Ann Davy at firstname.lastname@example.org.
Innovative technology designs are increasing efficiencies.
Technology for reusing flowback and produced water offers solutions for regions facing limited water sources and drought.
Rate limiting control devices optimize reservoir sweep.