Brett Davidson

Pressure Pulsing at the Reservoir Scale: A New IOR Approach

Laboratory tests initiated in January 1997 demonstrated clearly that periodic, large-amplitude, low-frequency stran excitation of porous media leads to large flow enhancements. Based on these results, a new liquid flow enhancement technology for reservoirs was formulated, and a successful full-scale field experiment was executed in early 1999. Other field projects in 1999 through 2001 waterfloods in heavy oil cold production wells with sand influx confirmed the expectation that pressure pulsing, properly executed, increases oil production rate at low cost. The first trial showed that period application of large amplitude, liquid-phase pressure pulses increased oil production rates, decreased water-oil ratio, and increased the percentage of sand produced, even without large-scale injection. Though experience to date is in heavy oil, the process is general and will work in all porous media that have interconnected pore space. Furthermore, the method works in single-phase and two-phase liquid saturated cases, although the presence of large amounts of free gas is detrimental. Based on the field and laboratory work, and considering the nature of the physical processes, it appears likely that pressure pulsing will also help reduce coning and viscous fingering instabilities, help overcome capillary blockages, and result in more total oil recovery over time.

Pressure Pulsing: The Ups And Downs of Starting a New Technology

W hen technology based on new science is started, there can be a lot of skeptici<,m, which is a healthy reaction. The ~kepticism encountered by PE-TECII as pressure pul!.ing is gradually introduced ha\ been partly overcome, but only in the Canadian heavy oil industry. Here arc some typical remarks we have encountered over the last three year:., accompanied by our responses. u se seismic excitation have, to our knowledge, met with failure in China, Canada, and the United States. Senior engineers from western oil companies have examined claims that mechanical vibrations are being used successfully, they appear unconvinced, even after site visits. Also, the numerous artic les in the Rus~ian

Dynamic Fluid Pulsation: A Novel Approach to Reservoir Stimulation Improves Post-Stimulation Gains

One of the major challenges to maximizing recovery of reserves is that every oil or gas reservoir rock is more or less heterogeneous at all scales (micro, mega, and pore) which leads to disproportionate production and injection outcomes. 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 a hydrocarbon reservoir inherently means improving flow through lower permeability regions. Ideally, during a conventional well stimulation using a treatment fluid such as acid, we wish to move the fluid through the majority of the rock volume but the physical constraints of fluid flow negatively impact that ideal outcome. Dynamic fluid pulse technology provides for high inertial fluid momentum which improves the flow efficiency of fluids injected into the wellbore, the near wellbore region, and the reservoir. The nature of fluid displacement energy ensures that pulsed fluid will penetrate the matrix proximal to where the tool is placed thus achieving enhanced fluid distribution. Prior to a stimulation operation a dynamic mathematical model associated with fluid pulse technology is employed to generate a precise well program (pumping schedule) to maximize the contact volume of the treatment fluid along the completed interval. Compared with conventional stimulation dynamic fluid pulsation has been demonstrated to bring significant financial benefits to well stimulation without impacting results including: reduced chemical costs; improved post-stimulation sustainability; and, better overall poststimulation well performance as a greater volume of the completed interval hence matrix is contacted by the treatment fluids. Introduction It is well known that the purpose of well stimulation is to remove wellbore “damage” or “skin” to restore a well’s productivity or injectivity. It has been postulated that the depth of radial damage that may occur in a formation can extend to 20 ft. (~6 m) and can emanate from drilling, completions, workovers, other stimulation procedures as well as production, water or gas injection, EOR activities, pressure changes in the reservoir, mobilizing solids, asphaltene, waxes, swelling clays etc. Every oil reservoir rock is more or less heterogeneous at all scales of (micro, mega, and pore). 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 inherently means improving flow through lower permeability regions. Ideally, during a well stimulation using a treatment fluid such as acid, we wish to move the acid through the entire rock volume but the physical constraints of fluid flow negatively impact that ideal outcome. First, injecting a low-viscosity fluid (i.e., acid) into a higher viscosity fluid (i.e., oil) results in the formation of viscous instabilities (“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 chemicals are injected to treat existing conditions in the reservoir with an attempt to achieve better well outcomes. In carbonates, matrix acidizing with HCl is widely used to enhance permeability by creating “wormholes.” In sandstones mud acids (HCl and/or HF) may be used to dissolve damage in the near wellbore region. In heavy oils, diluents (e.g. naphtha), dissolving agents (e.g. xylene) or other fluid constituents are used for a variety of reasons to enhance well productivity. The use of chemicals in treating wells has greater efficacy when the fluids are placed along the completed interval with both maximum distribution and depth of penetration. Conventional steady-state injection methodologies as well as jetting tools, acoustic tools or fluidic oscillators with chemicals are limited in their effectiveness to achieve these attributes because those approaches do not have the capacity to overcome difficult reservoir conditions such as low permeability streaks, very viscous oil, and sometimes even worse, the presence of fractures, fissures, and thief zones. Such formation characteristics reduce treatment effectiveness as the chemicals merely follow the pre-established flow pathways. To combat preferential flow often mechanical packer isolation or chemical diverts are used to try to “force” treatment fluids into lower permeability flow zones. The latter may lead to further damage in the reservoir while the former has limited effectiveness in the open hole or completed intervals. 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, Figure 1, has a saw-tooth shape providing several benefits over other established stimulation methods. The sharp change in pressure (amplitude) in a very short period of time (rise time) 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 the difficult reservoir conditions previously mentioned. However, it is important to note that the difference in pressure is only a small piece of the puzzle; how the change in pressure is created is a differentiating 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 because: • The pressure gradients involved in 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 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