Wells – Processes – Placing fluid into the formation
Reexamination Certificate
1999-10-25
2001-05-08
Neuder, William (Department: 3672)
Wells
Processes
Placing fluid into the formation
C166S263000, C166S400000
Reexamination Certificate
active
06227296
ABSTRACT:
FIELD OF THE INVENTION
This invention relates generally to the field of conditioning and treating the subterranean region near a wellbore, and more particularly to a method for reducing the water saturation in the near-well region of a subterranean formation. The inventive method may be used to facilitate various formation treatment procedures such as for increasing the injectivity rate of a substantially nonaqueous fluid into a subterranean formation.
BACKGROUND OF THE INVENTION
Water is naturally present in most subterranean formations of depositional origin including, without limitation, oil and gas reservoirs and coal deposits. In certain circumstances, it is desirable to displace water from a region near a wellbore in order to use treatment chemicals or procedures that may be adversely affected by excessive water, either through dilution or interference with the desired reaction. Examples of procedures that generally benefit from reduced water saturation in the near-well region include sand consolidation and polymer squeeze jobs, as well as other techniques that would benefit from greater contact with the reservoir matrix. In other circumstances, displacement of the water may itself be the desired treatment result. For gas injection used in tertiary recovery processes and other applications, educing the water saturation in the near-well region has a significant beneficial impact on gas injectivity. As used herein, the “near-well region” means that region in the vicinity of a wellbore the properties of which generally affect the flow of fluids into or out of the wellbore itself (as opposed to general reservoir flow patterns), usually, but not limited to, a radius of approximately two to as much as about fifty feet around the wellbore.
Although sand consolidation is no longer widely used, patents and publications from the 1970s suggest a variety of specific solvents to preflush the formation for water removal. Water interfered with successful sand consolidation more than oil, but oil removal was a secondary objective in many of the preflush proposals. The primary focus in selecting preflush solvents for sand consolidation work was on miscibility with both water and oil, with much of the selection process actually growing out of efforts to remove oil from the near-well region.
Several patented processes have also been presented for conditioning the near-well region for the purpose of acidizing the formation, with the focus in these patents being on oil removal to avoid the formation of emulsions during or after treatment. Few existing patents have addressed procedures focussed on the reduction of water saturation, especially as it relates to non-oil-bearing formations such as gas reservoirs or even aquifers. In itself, reduction of water saturation in the near-well region as a conditioning step before treatment will reduce dilution of treatment chemicals, allow better contact with the formation, and allow the use of treatments incompatible with water. In other cases, reduction of water saturation in the near-well region improves the relative permeability of the formation to oil, gas, or any other nonaqueous fluid. Changing relative permeabilities affects the potential recovery of oil or gas from a reservoir.
A significant amount of the crude oil contained in a subterranean formation is left in place after primary and secondary recovery processes. The crude oil left behind after secondary recovery processes can be as high as 20 to 50% of the original oil in place (OOIP). Water will also be present in the reservoir, as naturally occurring connate water, as a result of natural water drive, or as a result of injection for artificial water-flooding. Water as used herein will include any of the above, as well as fresh water, artificial brine, or any aqueous solution (e.g., solutions containing surfactants, polymers, acid, or any other additives) which might have been injected into the reservoir formation. Water saturation, S
w
, is expressed as a percentage of the relevant reservoir pore volume, herein generally a percentage of the near-well pore volume.
Various tertiary recovery processes using solvents, chemicals, polymers, heat (including steam), or foams have been proposed or used to recover an additional percentage of the OOIP by improving the relative flow characteristics of the reservoir fluids and/or by sweeping reservoir fluids toward a production well. The economic and/or physical effectiveness of these processes often depends on maximizing contact with the remaining oil in the minimum possible time. Balancing maximum contact with minimum time makes the injectivity of the tertiary recovery materials into the reservoir a critical factor. Of course, the economics for any particular process are also dependent on the cost of the materials required. While solvents, chemicals, polymers, and surfactants, including those used to generate foams, vary in cost, the ready availability of carbon dioxide or natural gas often lead to lower cost per barrel of oil recovered than for other processes.
The objective of tertiary recovery processes is to reduce the residual oil saturation in the reservoir to its lowest possible value, thereby maximizing recovery of the OOIP. Residual oil saturation depends on the capillary number (defined more fully below), which in turn is dependent on fluid velocity, viscosity, and interfacial tension. As used herein, capillary number is an expression representing how readily a given fluid flows through the restricted pore spaces in the reservoir relative to the other fluids present. For example, miscible and near-miscible solvents blend with oil to reduce viscosity and eliminate (or significantly reduce) interfacial tension, thus maximizing the capillary number for the oil, which in turn leads to decreased residual oil saturation.
Solvent miscible flooding uses solvents that are either miscible with or near-miscible with the crude oil left behind by primary and secondary recovery processes. Some examples of solvents which could be used in miscible flooding include natural gas, methane, ethane, other natural gas components, condensate, alcohols, ketones, micellar solutions, carbon dioxide, nitrogen, flue gas and combinations of these. Generally, both economics and commercial availability make solvent gases more attractive than liquid solvents for use in miscible flooding. However, oil recovery from solvent gas processes is negatively impacted by the unfavorable mobility and density ratios between the oil and solvent gas, which lead to poor sweep efficiency. Specifically, an unfavorable mobility ratio between the gas and the oil allows solvent gas fingering or channeling resulting in low oil recoveries because not all of the residual oil is contacted by the solvent gas. Likewise, unfavorable density ratios can cause the solvent gas to migrate to the top of the reservoir bypassing much of the crude oil.
Often water injection is alternated with the solvent gas injection to mitigate the poor sweep performance of a solvent gas process. This process is called a Water-Alternating-Gas (WAG) process. A solvent process has better sweep when the water and solvent flow together in a commingled zone because water has a lower mobility ratio with respect to oil than the solvent gas does. The water tends to help sweep both the oil and the solvent gas through the reservoir. In a WAG process, the fraction of the reservoir swept by the solvent gas (the commingled zone) is proportional to the injection rate of the solvent gas. Therefore, increasing the injection rate can increase the sweep efficiency of a WAG process.
A more expensive alternative used to address the problems with sweep efficiency in WAG processes is to use a Surfactant-Alternating-Gas (SAG) process to generate foam in the reservoir. Foam in tertiary recovery projects reduces gas mobility in the reservoir, improving sweep efficiency more than water alone. Foam has the added advantage of preferentially reducing gas mobility in high permeability areas of the reservoir, further improving sweep efficiency in the l
Idol W. Keith
Reppert Todd R.
Dougherty Jennifer R.
ExxonMobil Upstream Research Company
Katz Gary P.
Kubena Linda A.
Neuder William
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