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Controlling excess water production

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All oil fields under waterdrive, either from waterflood or a natural aquifer, eventually produce water along with oil. Even gas-cap and depletion reservoirs may produce some water. This coproduction of water can cause problems such as:

For these reasons, as well as economics, excess water production is not desirable. The material presented in this section that deals with water control technology has been abstracted from a detailed review of water problems and control technology.[1] This review contains the references to the original literature.

Water production

The present worldwide daily water production from oil wells averages roughly 3 BWPD per barrel of oil, although some wells produce significantly higher amounts. It costs money to lift water and then dispose of it. In a well producing oil with 80% water cut, the cost of handling water can double normal lifting costs. Yet, wells with water cuts in excess of 90% may still produce sufficient hydrocarbons to be economical (e.g., certain wells in the North Sea Shell Expro Brent fields and in the BP-Amoco Forties fields). Water control technology is intended to reduce the costs of producing water.

It is not necessary, nor desirable, to completely shut off the coproduced water. The logic here is the distinction between “good” (necessary) and “bad” (excess) water.[1] “Good” water is that water produced at a rate below the water/oil economic limit (i.e., the oil produced can pay for the water produced). “Good” water, then, is that water that cannot be shut off without reducing oil production. The fractional water flow is dictated by the natural mixing behavior that gradually increases water/oil ratio (WOR). “Good” water is also caused by converging flowlines from the injector to the producer wellbore. Water breakthrough on injection occurs initially along the shortest (least resistant) flow path between injector and producer, while oil is still being swept along other flow paths.

“Bad” water is water produced into the wellbore that produces no oil or insufficient oil to pay for the cost of handling the water. The remainder of this discussion deals with “bad” water.

Water intrusion

There is no one mechanism for “bad” water intrusion, and there is no one technology that will shut off water intrusion. There are 10 basic types of water problems.[1]

Problems that are relatively easily controlled:

  • Casing, tubing, or packer leaks.
  • Channel flow behind the casing from primary cementing that does not isolate water-bearing zones from the pay zone.
  • Moving oil/water contact (OWC).
  • Watered-out layer without crossflow—this is a common problem with a multilayer production and high-permeability zone isolated with flow barriers (e.g., a shale bed) above and below the zone. It is shown schematically in Fig. 1.[1]

Problems that are more difficult, but control is still feasible.

  • Fractures or faults between injector and producer.
  • Fractures or faults from a water layer. Water can be produced from fractures that intersect a deeper water zone.

Problems that do not lend themselves to simple and inexpensive near-wellbore solutions and require completion or production changes as part of the reservoir management strategy (e.g., multilateral wells, sidetracks, coiled tubing isolation, and dual completions).

  • Coning or cusping. Coning occurs in a vertical well when there is an OWC near the perforations with a relatively high vertical permeability driving high flow rates.
  • Edge water from poor areal sweep. Areal permeability anisotropy causes this problem.
  • Gravity-segregated layer. In a thick reservoir layer with high-vertical permeability, water, either from an aquifer or injector, slumps downward in the permeable formation and sweeps only the lower part of the reservoir (Fig. 2).[1]
  • Watered-out layer with crossflow. This is difficult, if not impossible, to treat.

Effective water control is generally predicated on knowing the position and mechanism (source) of the intruding water. These parameters may be established from direct measurement, the well’s production logs, and production history.

“Accurate production logs…can show water entry into the wellbore. The tool can determine flow and holdup for each fluid phase in vertical, deviated and horizontal wells. The addition of new optical and electrical sensors incorporating local probe measurements and phase velocity measurements have resulted in major improvements in the diagnosis in both complex and simple wells with three-phase flow. Such advances in reliable and accurate production logging, particularly in deviated wells with high water cuts represent a major step forward in identifying and understanding water problem types. A production log can be turned into a multilayer production log or a ‘multilayer test’ by measuring the production rate of each layer at several different producing pressures with station measurements positioned between each layer. In this way, crossflow potential can be measured. Wireline formation pressure measurements such as those with the MDT [modular formation dynamics tester] tool or the repeat formation tester (RFT) tool can show if the layers are in communication. A vertical interference test performed with the MDT tool will show vertical permeability near the wellbore. Log correlations can demonstrate whether extensive shale permeability exists across a field. A production log (spinner) may detect wellbore crossflow during well shut-in.”[1]

Production history can be used in a number of ways. First, there is the “recovery plot”: a semilog plot of water/oil ratio (WOR) vs. cumulative production, allowing extrapolation to the WOR economic limit (where producing water equals the value of the oil produced). If extrapolated production is approximately equal to the expected reserves, the well is producing acceptable (“good”) water and no water control is necessary. Next, there is the production history itself—a log/log plot of oil/water rates vs. time. Good candidates for water control show an increase in water production and a decrease in oil production at about the same time. Also, there is the decline-curve analysis: a semilog plot of oil production vs. cumulative oil. A sudden increase in decline may indicate a water problem or severe pressure depletion caused by damage buildup. And finally, there are diagnostic plots: log/log plots of WOR vs. time. Three basic signatures (patterns) distinguish between different water-breakthrough mechanisms (Fig. 3).[1]

Shut-in and choke-back analysis of the fluctuating WOR data can provide clues to the problem type. Water-entry problems such as coning or a single fracture intersecting a deeper water layer will lead to a lower WOR during choke-back or shut-in. Fractures or a fault intersecting an overlying water layer have the opposite effect.

Injection problems

There can be additional problems associated with the injector well—primarily because of unplanned and uncontrolled fracturing of the receiving reservoir. One mechanism arises from the buildup of solids because of, for example:

  • Filtration
  • Bacterial action
  • Scale buildup
  • Changes in reservoir wettability

Pressure is increased to maintain injectivity and fracturing may occur. Thermal fracturing is often encountered offshore, because of the stress reduction in the injection zone from cool down. The zone with the highest injectivity cools down first and fractures, taking even more injection fluid creating poor sweep efficiency. One strategy to control this problem is to deliberately fracture all receiving zones, increasing sweep efficiency.

Limiting water production

Mechanical or inflatable plugs are often the solution of choice for the near-wellbore problems:

  • Casing leaks
  • Flow behind casing
  • Rising bottom water
  • Watered-out layers without crossflow

These plugs can be deployed on coiled tubing or wireline to ensure shutoff in cased and openhole environments. When the wellbore must be kept open to levels deeper than the water entry, a through-tubing patch may be deployed inside the casing. One technology involves placing a flexible, inflatable composite cylinder made of, for example, carbon fiber, thermosetting plastics, and a rubber skin opposite the area to be treated. A pump then inflates the sleeve and injects well fluid, which heats the resins, turning on the polymerization process. After the resins have set, the sleeve is deflated and extracted.

Rigid gels are highly effective for near-wellbore shutoff of excess water. Unlike cement, gels can be squeezed into the target formation to give complete shutoff of that zone or to reach shale barriers. They have operational advantages over cement treatments because they can be jetted rather than drilled out of the wellbore. Commercial gels can be bullheaded into the formation to treat problems, such as flow behind casing and watered-out layers without crossflow, or they can be selectively placed in the water zones using coiled tubing and a packer.

Certain crosslinked polymers can also have long working times before becoming rigid. They are injected into small faults or fractures but only penetrate formations with permeabilities greater than 5 darcy. Large volumes (1,000 to 10,000 bbl) of these inexpensive fluids often successfully shut off extensive fracture systems surrounding waterflood injector or producing wells.

Gel treatments are not generally successful for combating coning/cusping problems for prolonged times, because they require very large volumes to be effective. An alternative is to drill one or more lateral drainholes near the top of the formation to take advantage of the greater distance from the OWC and decreased drawdown. Another approach is a dual drain (Fig. 4).[1]

Gel treatments are also not likely to work on the “gravity-segregated-layer” problem. Lateral drainholes may be effective in accessing the unswept oil. Infill drilling is often the best approach to improving the areal sweep efficiency edgewater problem. A large, likely uneconomic treatment of gel would be required to divert the injected water away from the pore space that has already been swept by water.

Treatments for water problems in horizontal wells are most effective when the treatment zone is isolated from the remainder of the wellbore. In cased holes, this is achieved mechanically with packers. However, when a screen or liner has been run but left uncemented, such mechanical devices are not effective in isolating the open annular space behind the pipe. One product developed for such situations is the annular chemical packer (Fig. 5).

Proactive water control includes choking back zones with high permeability to create a more uniform sweep. This means sacrificing early cash flow for an uncertain return because of incomplete knowledge of heterogeneity. The production (and injection) profile can be improved through selective stimulation of zones with lower permeability. Coiled tubing is used to precisely place these small hydraulic fractures.

Water disposal

Whether water production is minimized or not, some water (e.g., “good” water) will be produced and must be disposed. To minimize costs, the water should be removed as early as possible (e.g., with a downhole separator if possible); see Fig. 6.[1].


  1. 1.00 1.01 1.02 1.03 1.04 1.05 1.06 1.07 1.08 1.09 1.10 1.11 1.12 1.13 Bailey, B. 2000. Water Control. Oilfield Review 12 (1): 30.

Noteworthy papers in OnePetro

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External links

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See also

Water influx models

Produced oilfield water


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