Water shut off isn't the most glamorous of activities in the oil patch, but it is one that can quickly turn water flow into cash flow.

There are several different methods for mechanical shut off of unwanted water production. To determine the best one, some analysis is required. The first order of business is to determine the source of the water influx. This usually has the greatest influence on the development of a successful counterattack.
Water influx can come from any number of sources. The most common is from open perforations that are communicating with a pay sand that has started producing water. Water can be coning up as a result of high drawdown, or it can be entering through high conductivity laminae or fractures. Bad cement jobs account for a lot of water problems, and allow water to travel up or down along the casing annulus to find open perforations or a casing leak that provides a path into the well. The usual fix for cement problems is to perforate and squeeze cement to attempt to reestablish the hydraulic integrity of the annulus. Unfortunately, there are times that this technique fails or produces marginal results.

The good news is that, usually, water influx can be quickly pinpointed using common through-tubing production logging (PL) tools. These can be either the electrical wireline variety that provide real-time readouts, or memory tools that run on slickline and are de-programmed upon retrieval. One thing is certain, the water isn't going to suddenly go away, so time is not the most critical factor. Getting the right solution is. The PL tools, in addition to pinpointing the water source, can quantify it in situ so the operator can see exactly how big a problem exists. Measurements include multiphase flowmetering, and water-cut calculations. These answers plug into software programs that can model the present and future economic effect of the problem and calculate the net present value and payout schedule of various solution options.
Putting squeeze cementing aside, there are several mechanical water shut-off solution possibilities that are quick, economical and effective. These include bridge plugs that can be deployed by electrical wireline, slickline, or by a workover string consisting of jointed pipe or coiled tubing. Many can be deployed through tubing, eliminating the need to pull the completion. In addition to bridge plugs are scab liners, consisting of two or more inflatable packers connected by an intervening tubular that effectively straddles the water entry point. In some cases the straddle technique can be used to inject a chemical relative permeability modifier treatment through the open perforations into the water-producing formation. These can reduce the relative permeability to water and enhance the relative permeability to hydrocarbon. This solution is used when there are still commercially viable hydrocarbons remaining in the zone. Dramatic results have been obtained using these techniques. Of course, if the zone has watered-out and there appears to be no residual value, chemicals can be squeezed that will shut off all fluid production from the zone.

Several recent case histories illustrate the options:

Bridge Plug to shut off lower water producing perforations

Recent recompletions performed in Trinidad included five gas wells that were shut in for a 2-year period due to 100% water production. After analysis showed water was encroaching from a watered-out zone at the bottom of the completion, through-tubing bridge plugs were determined to be the most economical solution.

Bridge plugs were run on slickline, cement was dumped on top of the bridge plugs, and the wells were re-perforated up hole. The wells are now producing 10 MMcfg/d to 23 MMcfg/d with no water production. This option was determined to be much cheaper than moving in a rig and doing a full-blown workover. The plugs run were 21/8-in. and 21/2-in. outside diameter (OD) and they were set inside 7-in. casing. (Figure 1).

Retrievable Scab Liner to shut off water producing middle perforations

Several wells have used this solution in Australia, Cabinda and Canada. The wells had water production entering the well from the middle set of perforations, and oil from upper and lower perforations. The Cabinda well was deviated and in that case the deployment method was slickline. The tool OD was 29/16-in. and it was set in a 5-in. liner (Figure 2).

In Australia, the situation involved a horizontal section of the well, and deployment was by a snubbing unit. The tools' ODs were 29/16-in. in a 51/2-in. liner and 35/8-in. in a 7-in. liner, respectively.

Dual lateral horizontal well

In Canada, a well was completed with two lateral branches commingled. The well was making 100% water. Each lateral was tested separately and water was discovered coming from Leg No. 2. A scab liner was run on the workstring and the lower inflate was set in Leg No. 1. The upper inflate was set in the mother bore above the junction, effectively isolating Leg No. 2 (Figure 3).
Production from Leg No. 1 increased to 73% oil after the workover.

Chemical placement

As mentioned, water-inhibiting chemicals can be injected in open hole, casing, or through tubing using bridge plugs and packers, or straddle tools. The packers are multiset packers that can be used for testing prior to pumping chemical, and for post-job evaluation following the treatment (Figure 4).

Summary

With careful analysis, the cause of water influx can be determined, leading to the most cost-effective solution selection. Operators can now choose from a wide variety of sizes and field-proven techniques to shut off water flow and resume cash flow.