|Theme||Visible||Selectable||Appearance||Zoom Range (now: 0)|
Formation damage caused by drilling-fluid invasion, production, or injection can lead to positive skin factors and affect fluid flow by reducing permeability. When mud filtrate invades the formation surrounding a borehole, it will generally remain in the formation even after the well is cased and perforated. This mud filtrate in the formation reduces the effective permeability to hydrocarbons near the wellbore. It may also cause clays in the formation to swell, reducing the absolute permeability of the formation. In addition, solid particles from the mud may enter the formation and reduce permeability at the formation face.
There are components provided by the ESP manufacturers and other suppliers that provide additional mechanical and electrical protection, monitoring, or performance enhancements in the operation of an artificial lift system using electrical submersible pumps. Installation of such components on all wells may not be justified, but their use on key wells should be carefully considered. Because the ESP operates in a hostile and confined environment, monitoring how it operates is very difficult. Additionally, it is also difficult to find sensors and electronics that operate reliably and long term under the range of downhole conditions required. The ESP's reliability or run-life is directly related to the continual monitoring of its operating parameters and the wellbore conditions. Not only is this information critical to the run-life, but it is also important for the evaluation of the application design of the ESP system in the hole.
While typical production operations seek to prevent sand production, cold heavy oil production with sand (CHOPS) operations use sand production to increase overall productivity. This difference can create operational issues throughout the life of a CHOPS well. It has implications for monitoring strategies as well. To initiate sand influx, a cased well is perforated with large-diameter ports, usually of 23 to 28 mm diameter, fully phased, and spaced at 26 or 39 charges per meter. More densely spaced charges have not proved to give better results or service, but less densely spaced charges (13 per meter) give poorer results. More densely spaced charges may eliminate reperforating as a future stimulation choice because full casing rupture is likely to take place.
The success of an acidizing operation can be compromised if the wellbore, tanks, or other equipment contain solids or other contaminants that could flow into the well or formation. Proper preparation is a key factor in a successful acid treatment. Treating fluids must leave surface tanks, travel through surface pipe and well tubing, enter a wellbore, and pass through the perforations into the formation so that the solvent can react with the damaging solids. Each of these components through which the fluid travels must be properly cleaned before pumping acid into the formation. Surface tanks must be cleaned before being filled with acid.
If the problem is formation damage, then matrix acidizing may be an appropriate treatment to restore production. This page discusses ways to evaluate whether a well is a good candidate for acidizing. This plugging can be either mechanical or chemical. Mechanical plugging is caused by either introduction of suspended solids in a completion or workover fluid, or dispersion of in-situ fines by incompatible fluids and/or high interstitial velocities. Chemical plugging is caused by mixing incompatible fluids that precipitate solids.
A leading cause of unsuccessful acid treatment is failure to contact all the damage with the acid. Fluids pumped into a formation preferentially take the path of least resistance. This makes the placement and coverage of the acid an important component of the treatment design. In a typical treatment, most acid enters the formation through the least damaged perforation tunnels, as the schematic in Figure 1 shows. When this happens, it can be readily concluded that acidizing does not work well and is expensive.
The earliest gravel packs were performed in shallow, vertical wells, typically by simply pouring gravel into the tubing/casing annulus and allowing the gravel to settle around a screen. Some screens were even washed into place after the gravel was placed. The technique is still employed in water wells but now is seldom used in oil/gas wells. As equipment and technology improved, gravel packing of oil/gas wells was accomplished by mixing sand in brine and pumping the mixture into the hole. Brine represents the simplest of the transport fluids.
Gravel packing consists of installing a downhole filter in the well to control the entry of formation material but allow the production of reservoir fluids. The gravel-packed completion is perhaps the most difficult and complex routine completion operation because it consists of many interrelated completion practices. There are two primary objectives for gravel packing a well. The crossover circulating technique is the most common method used to place the gravel around the screen. The gravel-pack equipment and service tools allow circulating the gravel down the work string above the packer and into the screen/casing annulus below the packer.
Pumping proppant down a wellbore is the easy part. Ensuring that the precious material does its job is another matter. A trio of field studies recently presented at the 2020 SPE Annual Technical Conference and Exhibition (ATCE) highlight in different ways how emerging technology and old-fashioned problem solving are moving the industry needle on proppant and conductivity control. These examples include the adoption of unconventional completion techniques in a conventional oil field in Russia and work to validate the use of small amounts of ceramic proppant in North Dakota's tight-oil formations. Both studies seek to counter widely held assumptions about proppant conductivity.