Excessive water production in reservoirs

By: Marcelo Reyna

As oilfields mature, the probability of producing significant percentages of water increases. Many reservoirs produce by the thrust of a natural aquifer, whose waters break through at some point in their productive life; others are produced by secondary or enhanced oil recovery (EOR) methods that include artificial injection of water down the reservoir flanks or by geometric arrangements of injector and producer wells. Unconventional hydrocarbon reservoirs require large volumes of water that are produced after injection for fracturing, in addition to the connate water that is produced as a consequence of this process.
In all cases, excessive water production becomes a problem, given the adverse effects it has on the production capacity, treatment and handling of hydrocarbon streams from the reservoir to the shipment.

Some data that show the magnitude of the problem in water production are:

  • The world average percentage of water from oil wells is 75%, i.e., three barrels of water are produced for every barrel of oil. World daily water production exceeds 250 MMBPD.
  • Production year 2001: approximately 210 MMBAPD, associated with 75 MMBNPD
  • Oil and gas production is increasing rapidly and, by 2035, oil production is expected to increase to 97 million barrels and water production is expected to reach 300 million barrels per day.
  • Annual cost associated with water production of over $45 billion
  • It is estimated that for every 1% reduction in global water production, oil industry savings can reach up to US$100 MMUS per year.

The criteria for estimating the costs associated with unwanted water production are many and very dissimilar. Estimates range from 5 to more than 50 cents per barrel of water, depending on the criteria and operating conditions. This means that in a well that produces oil with an 80% water cut, the cost of water management can amount to $4 per barrel of oil produced. Experts agree to use an average value of US$ 0.5 for the cost of each barrel of water produced.
In most cases, this production cost does not reveal the full extent of the problem since it does not quantify the impact on the life of the reservoir-well asset. In many fields it is unfeasible to produce wells above a certain percentage of water, either because of limited surface facilities or for production cost reasons. In these cases, the wells whose water cut exceeds the economic and operational limit are systematically shut down and do not allow the recovery of a significant amount of reserves that remain in the subsoil. In short, the greatest impact of uncontrolled water production is the trapped oil that we stop producing.
Figure 1. shows the case of a field whose economic limit is 95% water. Limiting water production and deferring this situation by means of some remediation treatment may mean recovering a production of 150 MMBls that would otherwise be impossible to extract.


Fig. 1. Cumulative oil production vs. water cut of a reservoir.

When a reservoir produces water, a series of collateral problems arise, among which we can list the following:

  • Higher energy consumption due to the increased weight of the crude column to be lifted from the reservoir.
  • Corrosion in production pipelines and conveying lines
  • Precipitation of carbonates and sulfates (scale) capable of clogging underground production equipment and production and transportation pipelines.
  • Formation of emulsions, which must be chemically separated at the surface facilities.

Formation waters are highly contaminating, requiring purification treatments before being discharged into the environment. In other cases, it is required to be re-injected to the subsoil, for which it is necessary to drill wells for this purpose.
In many scenarios, the most desirable is to control water production from the bottom of the well, to avoid this whole chain of consequences in surface facilities.


Figure 2. Schematic diagram of the produced water cycle

In this context, overcoming the challenges involved in the application of technologies to solve or mitigate the problem of excessive water production will make it possible:

  • Increase the useful life of the wells, improve recovery.
  • Reduce costs for disposal, treatment and handling of fluids.
  • Decrease energy requirements and lifting costs.
  • Reduce risks of spills and corrosion problems, avoid production losses.
  • Avoid production losses due to incrustations in pipes and equipment.
  • Reactivate wells closed due to high water cut.
  • Comply with environmental laws.
  • Care for the Corporation’s image in the community.

Water production mechanisms in oil wells
Elphick et al. made a classification of the problems and conditions of the wells that lead to high water production, identifying 10 well differentiated cases. The cases (1 to 5) are shown schematically in Fig. 3a.
Case 1. Leakage: The corrosiveness of the water and some faults in the cement produce a hole in the casing of the well, causing the irruption of water from the reservoir in an unpiped area of the well.
Case 2. Flow behind casing: The cement is not well bonded to the well casing and allows water from a highly water-saturated aquifer or formation to flow behind the casing until it finds its way into the wellbore in the vicinity of the perforations.


Figure 3.a. Irruption modes of water from reservoirs

Case 3. Dynamic CAP (Water-Oil Contact): the water-oil contact is displaced by the sweeping effect in the reservoir until it reaches the height of the perforations.
Case 4. Matrix channeling without cross flow. Water flows through a high permeability channel of the reservoir, isolated by hydraulic seals from the oil producing zone, reaching the boreholes.
Case 5. Fractures/fissures between Injector and Producer: In injector-producer well arrangements, a permeable fracture system connects the injector and the producer. This circuit allows the preferential flow of water, producing the early irruption of water into the producer well.
Case 6. Fractures Fissures between producer and aquifer. Similar to case 5, but the fracture system connects the aquifer with the producing zone.


Figure 3.b. Irruption Modes

Case 7. Coning and cresting: water from a lower aquifer is attracted to the boreholes due to the pressure difference and the greater mobility of the water in relation to the oil. A water cone is formed, which bursts into the crude oil zone until it prevents its production. The same phenomenon in a horizontal/ deviated well looks like the crest of a wave and is called “cresting”.
Case 8. Poor areal sweep: In systems with producing injector arrays, reservoir heterogeneity causes non-uniform distribution of injection water and hence inefficient sweep to some wells and early breakthrough to others.
Case 9. Gravitational segregation: the gravitational effect overcomes the capillary effect and the injection water tends to segregate towards the lower zone of the producing well, causing inefficient sweep and early breakthrough.
Case 10. Matrix channeling with cross flow. Similar to case 4, but since there are no barriers separating the offending zone from the producing zone, there may be cross flow between them.
Cases 2,4,5 and 6 are the most susceptible to be successfully treated by injecting polymeric gels. Few successful cases are documented in the application of gels for conification control (case 7).

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