Sand control techniques
Several techniques are available for minimizing sand production from wells. The choices range from simple changes in operating practices to expensive completions, such as sand consolidation or gravel packing. The sand control method selected depends on site-specific conditions, operating practices and economic considerations. This page introduces the available approaches to sand control.
Available techniques
Some of the sand control techniques available are
· Maintenance and workover
· Rate exclusion
· Selective completion practices
· Plastic consolidation
· High energy resin placement
· Resin coated gravel
· Stand-alone slotted liners or screens
· Gravel packing
Maintenance and workover
Maintenance and workover is a passive approach to sand control. This method basically involves tolerating the sand production and dealing with its effects, if and when necessary. Such an approach requires bailing, washing, and cleaning of surface facilities routinely to maintain well productivity. It can be successful in specific formations and operating environments. The maintenance and workover method is primarily used where there is:
· Minimal sand production
· Low production rates
· Economically viable well service
Rate restriction
Restricting the well’s flow rate to a level that reduces sand production is a method used occasionally. The point of the procedure is to sequentially reduce or increase the flow rate until an acceptable value of sand production is achieved. The object of this technique is to attempt to establish the maximum sand-free flow rate. It is a trial-and-error method that may have to be repeated as the reservoir pressure, flow rate, and water cut change. The problem with rate restriction is that the maximum flow rate required to establish and maintain sand free production is generally less than the flow potential of the well. Compared to the maximum rate, this may represent a significant loss in productivity and revenue.
Selective completion practices
The goal of this technique is to produce only from sections of the reservoir that are capable of withstanding the anticipated drawdown. Perforating only the higher compressive strength sections of the formation allows higher drawdown. The high compressive strength sections will likely have the most cementation and, unfortunately, the lowest permeability. While this approach might eliminate the sand production, it is flawed because the most valuable reserves will not be in communication with the well.
Plastic consolidation
Plastic consolidation involves the injection of plastic resins that are attached to the formation sand grains. The resin subsequently hardens and forms a consolidated mass, binding the sand grains together at their contact points. If successful, the increase in formation compressive strength will be sufficient to withstand the drag forces while producing at the desired rates. The goal of these treatments is to consolidate about a 3-ft radius around the well without appreciably decreasing the permeability of the rock.
Three types of resins are commercially available:
· Epoxies
· Furans (including furan/phenolic blends)
· Phenolics
The resins are in a liquid form when they enter the formation, and a catalyst or curing agent is required for hardening. Some catalysts are “internal” because they are mixed into the resin solution at the surface and require time and/or temperature to harden the resin. Other catalysts are “external” and are injected after the resin is in place. The internal catalysts have the advantage of positive placement because all resin will be in contact with the catalyst required for efficient curing. A disadvantage associated with internal catalysts is the possibility of premature hardening in the work string. The amounts of both resin and catalyst must be carefully chosen and controlled for the specific well conditions. Epoxy and phenolics can be placed with either internal or external catalysts; however, the rapid curing times of the furans (and furan/phenolic blends) require that external catalysts be used.
There are two types of plastic consolidation systems:
· “Phase separation” systems
· “Overflush” systems
Phase separation systems contain only 15 to 25% active resin in an otherwise inert solution. The resin is preferentially attracted to the sand grains, leaving the inert portion that will not otherwise affect the pore spaces. These systems use an internal catalyst. Accurate control of the plastic placement is critical because overdisplacement will result in unconsolidated sand in the critical near-wellbore area.
Phase separation consolidation may be ineffective in formations that contain more than 10% clays. Clays, which also attract the resin, have extremely high surface area in comparison to sands. The clays will attract more resin and because phase separation systems contain only a small percentage of resin, there may not be enough resin to consolidate the sand grains.
Overflush systems contain a high percentage of active resin. When first injected, the pore spaces are completely filled with resin, and an overflush is required to push the excess resin away from the wellbore area to re-establish permeability. Only a residual amount of resin saturation, which should be concentrated at the sand contact points, should remain following the overflush. Most overflush systems use an external catalyst, although some include an internal catalyst.
All plastic consolidations require a good primary cement job to prevent the resin from channeling behind the casing. Perforation density should be a minimum of four shots per foot to reduce drawdown and improve the distribution of plastic; however, each perforation must be treated. Shaley zones should not be perforated because fluids are difficult to place in these low-permeability strata. Clean fluids are essential for plastic consolidation treatments because all solids that are in the system at the time of treatment will be “glued” in place. The perforations should be washed or surged, workover rig tanks should be scrubbed, and fluids should be filtered to 2 microns. Work strings should be cleaned with a dilute HCl acid containing sequestering agents, and pipe dope should be used sparingly on the pin only. A matrix acid treatment, which includes HF and HCl, is recommended for dirty sandstones to increase injectivity.
Both phase separation and overflush systems require a multistage preflush to remove reservoir fluids and make the sand grain oil wet. The first stage, generally diesel oil, serves to displace the reservoir oil. Epoxy resins are incompatible with water; therefore, isopropyl alcohol follows the diesel to remove formation water. The final stage is a spacer (brine) that prevents the isopropyl alcohol from contacting the resin.
Plastic consolidation leaves the wellbore fully open. This becomes important where large outside diameter (OD) downhole completion equipment is required. Also, plastic consolidation can be done through tubing or in wells with small-diameter casing. For most applications, the problems associated with plastic consolidation outweigh the possible advantages. The permeability of a formation is always decreased by plastic consolidation. Even in successful treatments, the permeability to oil is reduced because the resin occupies a portion of the original pore space and is oil wet. The amount of resin used is based on uniform coverage of all perforations. However, perforation plugging or permeability variations often cause some perforations to take more plastic than others. In systems that use an external catalyst, there is no sand control in areas that are not contacted by both resin and catalyst.
The primary difficulty in using resin systems is attaining complete and even placement of the chemicals in the formation. In lenticular formations, plastic placement may be uneven because of widely varying permeabilities, and some zones are likely to be untreated. These untreated intervals may break down during subsequent production, and the well will sand up. For this reason, plastic consolidation is suitable for interval lengths less than 10 to 15 ft. Longer intervals can be treated using packers to isolate and treat small sections of the zone at a time, but such operations are difficult and time consuming. Plastic consolidation treatments also do not perform well in formations with permeabilities less than about 50 md. Low permeabilities preclude injecting resins under matrix conditions and cause permeability reductions by the plastic that substantially reduce residual permeability (i.e., well productivity). The resins soften at a temperature greater than 255°F and may not provide sufficient strength at elevated temperature.
Plastic consolidation was used extensively in the late 1950s through the mid-1970s in the Gulf of Mexico; however, this technique currently represents far less than 1% of all sand-control completions worldwide. The reasons for decreased usage include lack of suitable candidates, the placement difficulties already described, as well as tight regulations on the handling of the chemicals, which are generally quite toxic (with the furans being the least toxic of the three). These treatments tend to be costly. The main disadvantage of plastic systems in current operations is its high cost and limited completion interval length for an effective treatment, 15 ft or less. The latter excludes most wells. Because of its current limited use, service companies have difficulty maintaining trained crews.