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Seismic and Seismochemical Stimulation Increases Well Injectivity and Productivity

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Many oil fields in Russia and the Commonwealth of Independent States are in late-development stages, with waterflooding having being used for decades. A relatively new technology in production optimization is wave stimulation, in which the wellbore and reservoir are treated by acoustic, seismic, or other types of waves generated by tools. Approximately 250 wells have been treated in this manner, with a high success rate and significant oil-production increase. This paper discusses the potential of seismic and seismochemical well simulation in particular within the scope of this recent technology.

Introduction

Wave-stimulation technologies have short treatment times and can be applied in different types of formations and wells. This paper focuses on seismic-impact well treatment. The well treatment is based on a wellhead pneumatic generator that uses special valves. Energy is generated at the surface with compressed inert gas and released into the well. A shock wave then propagates through the liquid-filled well column and transforms into a seismic wave in situ. Movement of the shock wave creates a damped self-oscillating process with a frequency of 0.2 Hz, the effect of which can stimulate injection and production wells. One method of increasing the efficiency of seismic stimulation is use in conjunction with the injection of chemical reagents.

Mechanisms of Seismic and Seismochemical Stimulation

No generally accepted theory describes the effects of seismic impact on reservoirs. On the basis of theoretical, experimental, and field research, various authors have proposed mechanisms and concepts, which are described in the complete paper.

Porosity and Permeability Change in Dilatancy Area for Sandstones. Studies of dilatancy processes under dynamic effects have shown that, for sufficiently high unevenness of the stressed state, dilatancy processes occur even at stresses that are only 3–5% of the ultimate strength, causing irreversible change in the rock density, porosity, strength, and permeability.

Dilatancy is observed in the deformation of soils and rocks. Extensive experimental data on the deformation of a wide class of formations under volumetric stressed-state conditions show that compaction is seen in highly porous rocks, while loosening is seen in dense rocks. Reduction in the volume of highly porous rocks occurs as the result of a reduction in the number of defects. Positive (compaction) and negative (loosening) rock-dilatancy values are related to the value of the initial effective porosity. If the effective porosity value is less than a certain limiting value, then the rock is dense and loosens during deformation. When the effective porosity is greater than its limiting value, the rock is compacted. However, the compaction of the rock can occur up to a certain value, after which it breaks down.

The main influence on the amount of dilatancy is the result of an uneven load (i.e., the ratio of the minimum main stress to the maximum). However, at the same level and at the magnitude of the uneven loading in the stronger rocks, the dilatant component of the volume deformation exceeds the rock compaction more than is seen in less-rigid rocks.

Effect of Mechanochemical Processes on Properties of Reservoir Rock

The fracturing process initiated by surfactants significantly changes rock structure, and this inevitably affects many rock properties. In addition, the degree of fracture affects the behavior of most processes in the rock and determines their resistance.

Because of the adsorption of surfactants on the rock surface, a sharp loss of strength of the surface layer occurs, known as the adsorption reduction of hardness. Thus, to determine the efficiency and optimal concentration of surfactant solutions acting on a particular type of rock, the method for determining the hardness (contact stress) of wetted samples was used. The results show that, for any of the rocks studied, effective surfactants can lower the contact strength by 18–70%. The greatest effect is observed for polymineral highly porous (up to 10% and greater) rocks such as bauxites and effusive lithotypes of pyroxene/plagioclase composition. On the other hand, fairly uniform low-porosity (up to 2%) limestones are characterized by the least variability. This is caused by the rate of saturation of these rocks by surfactant solutions.

Combining Seismic Impact With Chemical Reagents To Improve Oil Displacement

The injection of carbon dioxide (CO2) into formations is a widely used method of enhanced oil recovery. The method of seismochemical stimulation technology combined with release of CO2 in situ allows optimization of the technology’s positive effects. During reactions in the reservoir, alkalis are formed also. This, in addition to CO2, also increases the efficiency of oil displacement in the near-wellbore region.

To optimize the effect of seismic impact, aqueous solutions of ammonium salts (ammonium carbonate and ammonium bicarbonate) were selected. With the use of carbon ammonium salts, the reactions of CO2 generation and (alkaline) ammonium hydroxide occur in the reservoir.

The process of oil displacement from oil-saturated cores with aqueous solutions at different concentrations and temperatures was studied experimentally. For samples with a permeability of 10–300 md and porosity of 20–24%, the increase in the displacement coefficient can range from 41 to 96% with respect to its initial value when only water is injected. At the same time, the maximum increase in the displacement occurs when the temperature is raised to 80°C.

Experimentation

Factors Affecting Fluid Mobility Under Reservoir Conditions. Natural cores were drilled from Grozny outcrops of oil- and gas-bearing sandstones. Several studies were carried out using cores selected from Neocomian and Jurassic sediments of western Siberia (sandstones with clay and carbonate cement). After the final firing, disks with a length of 20 mm were cut from the ends of the core to eliminate end effects. All materials used for cores were hydrophilic, which gave confidence in receiving porous media with a hydrophilic surface. Absolute and phase permeabilities were determined after placing the core in the core holder and loading the core with lateral and axial pressure simulating the rock pressure. On the basis of the results of such tests, the cores were divided into Group I and Group II.

Experiments have shown that, in Group I, the impulse action did not lead to any significant changes in permeability. In Group II samples, an opposite effect was observed: permeability increased by orders of magnitude. To determine the reasons for such a significant difference in the filtration properties of artificial samples, the experiments were repeated. After unloading the cores from the rock pressure in the samples, the original loading conditions were reproduced and an impulse action of the same power was carried out. Repeated exposure had no effect on the samples of Group I. Samples of Group II lost their singularity—the unique properties of Group II samples were associated with deformation by hydraulic pressurizing.

Despite the hydrophilicity of both Group I and II samples, the main difference was the formation of water molecules on the surface of Group II minerals of adsorbed layers. In Group II cores, electron emission was observed (by luminescence) with multiple impacts of the indenter, but in samples of Group I, emission was absent. The Group I samples belong to nondilated rocks, and the samples of Group II belong to dilated ones. Thus, under the conditions of occurrence, many layers can be characterized by the capacity for dilatancy during pulsed action.

Field Cases

Figs. 1 and 2 present the results of using seismic and seismochemical stimulation in the same well, Well 75, in western Siberia at different periods of time. It can be seen that seismochemical stimulation (Fig. 2) provides a greater increase of injectivity and a longer duration of the effect when compared with conventional seismic stimulation. It also results in higher incremental oil production in surrounding production wells (more than 4,000 tons). Averaging the results confirms the production-enhancement effect of complex seismochemical well stimulation.

Fig. 1—Conventional seismic stimulation: Injectivity of Well 75 (western Siberia).

 

Fig. 2—Seismochemical stimulation: Injectivity and wellhead pressure of Well 75.

 

In total, seismic stimulation has been used in approximately 250 wells to date. The complete paper presents field cases and statistics for all treatments. To date, injection and production wells (both vertical and horizontal) have been treated in various fields across Europe and Asia. There is a large range of temperature, salinity, and perforation intervals of treated wells. Formation depth in these fields is up to 3.5 km, and reservoir permeability is approximately 5 md. On average, stimulation of injectors increased injectivity by 85% for 18 months, leading to an incremental oil rate of 30% in treated patterns (a total of 45,000 bbl/treatment). Averaging producers’ treatment results gives a 65% increase in the oil-rate effect (a total of 12,000 bbl/treatment) lasting for 22 months. Typical unit technical cost (UTC) in these operations was below $2/bbl. As a rule, seismochemical treatments have larger UTCs and deliver higher increases in injectivity and productivity indices.

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 190456, “Increasing Well Injectivity and Productivity by Seismic and Seismochemical Stimulation,” by K. Furman, S. Miftakhov, SPE, M. Nazyrov, R. Nefedov, and V. Zamakhaev, Terratec, and A. Andrianov, AIA Consulting, prepared for the 2018 SPE EOR Conference at Oil and Gas West Asia, Muscat, Oman, 26–28 March. The paper has not been peer reviewed.

Seismic and Seismochemical Stimulation Increases Well Injectivity and Productivity

01 June 2019

Volume: 71 | Issue: 6

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