Water management

Water-Management Experience in a Mature Basin in South Argentina

As part of a comprehensive water-management strategy, this paper describes different process and operational considerations that are the result of 109 years of production in Argentina’s oldest basin.

Fig. 1—Typical water-production and -distribution scheme for the GSJB.

During oil production in mature fields, the implementation of waterflooding projects plays an important role in increasing oil production and the recovery factor of the reservoirs, and this is the case in the Golfo San Jorge Basin (GSJB) in Patagonia, Argentina. As part of a comprehensive water-management strategy, this paper describes different process and operational considerations that are the result of 109 years of production in Argentina’s oldest basin.

Water Production and Management in GSJB

The production history of the GSJB has included water production from the beginning, although, in recent years, the volumes have been increasing. The objective of water management has been to maximize the value of the assets by increasing oil production and the reserves recovery factor, reducing the production cost, and limiting or canceling environmental effects.

Water Production, Treatment, and Distribution

Managing production water involves the following activities:

  • Production
  • Treatment, distribution, and injection
  • Subsurface distribution
  • Integrity control of injector wells and surface installations

In terms of production, the water associated with oil is collected in production batteries and transferred to treatment and injection plants (Fig. 1 above). In some cases, the water is separated in these facilities and delivered to treatment plants. Once at the treatment plants, the water is conditioned and distributed through pumps to the water-injection wells.

Some of the equipment and techniques commonly used for the separation and treatment of injection water are

  • Free-water knockout or free-water tanks for water separation
  • Skimmer and sedimentation tanks for suspended-solids and oil removal
  • Suspended-solids removal by filtration
  • Dissolved-gas removal (e.g., oxygen, hydrogen sulfide, and carbon dioxide) by chemical treatment
  • Scale prevention by chemical treatment
  • Slime and bacteria control by chemical treatment
  • Corrosion control by chemical treatment

For distribution of the water, approximately 3,140 injector wells distribute the 3.2 million B/D of produced water, which is used as a source for secondary-recovery projects through waterflooding.
For the water injection, multistage centrifugal pumps at the injection plants and at booster units are used in most cases and reciprocating pumps are used for smaller projects. Field manifolds are used for distribution, flow-rate regulation, and measurement of the water injected in each well.

Recently, electromagnetic flowmeters and supervisory-control-and-data-acquisition systems have been used for surveillance of the injection process. In terms of flow regulation, this allows the injection rate to be kept constant, independent of the available pressure. If the system pressure increases, the regulator opens, allowing the same fluid-flow rate with a lower differential pressure. If injection pressure increases, the regulator will close automatically until the desired flow rate is maintained.

Waterflooding in GSJB: The Key for Water Management

The GSJB contains hundreds of waterflooding projects. Regarding different recovery levels, 46% of the total production of oil is from secondary recovery, 53% is by primary recovery, and 1% is from enhanced oil recovery (EOR). With respect to oil production from EOR, it could be considered incipient but will be key to increasing the oil recovery factor and improving the efficiency of the injected-water sweep. Accompanying this evolution, the percentage of water currently is 92.7%, with an incremental rate of 0.3% per year during the past 6 years.

Water Balance: Bottlenecks Analysis

The production and management of water in the GSJB should not be interpreted as only the management of waste but also as the source for maintenance of oil production. Regardless, the water-management capacity, from an operational point of view, must be evaluated because, in many fields, the inability to manage water leads to a loss of oil production. For this reason, the water balance and analysis of bottlenecks are fundamental to maintaining the production of oil and to evaluating the maximum capacity of water management from a technical and economic point of view.

When the water-handling limit is reached, at least two options exist: reduce the water production or increase the water collection (increase the station’s capacity), treatment, and injection. Both options, however, require technical and economic analysis.

Water-Management Effect on Total Cost

During the production of mature fields with high percentages of water, the costs associated with the production are directly related to the production of water. As the percentage of water increases, the cost to produce a barrel of oil will increase.

In GSJB, at least 28% of the lifting cost of production is directly related to the management of produced water and 25% of this cost is associated with energy consumption.

Well-Integrity Management

Meeting environmental security regulations requires perfect mechanical integrity for injector wells, including hermeticity in the casing/packer/tubing system and between the top packer and wellhead during the operational life of the well. To accomplish this, the Argentine Institute of Oil and Gas has developed a recommended practice that is applicable to injector wells for assisted recovery in areas that contain aquifers of interest suitable for human or agricultural consumption or for irrigation.

Artificial-Lift Challenges

Artificial lift is the first subprocess associated with production-water management and can be critical in advanced stages of mature-field operations.

Considering the restriction of casing diameter and the increased flow rate and pump depth per well, the maximum power transmission from the prime mover to the pump is a common factor for the three most common artificial-lift systems—sucker-rod pumps (SRPs), progressing-cavity pumps (PCPs), and electrical submersible pumps (ESPs). To enhance artificial-lift capability, new materials, designs, and operational conditions have been considered.

SRPs. The use of high-strength sucker rods and premium connections has become common practice recently. The use of long-stroke pumping units is another new practice that allows for greater flow rate and depth, to reduce the dynamic load.

PCPs. Similar to SRP systems, special sucker rods have been one of the more important practices. For increasing flow-rate capacity of the pump, the latest trends have been to increase the volumetric displacement in PCPs, increasing the stage length and reducing the eccentricity of the rotor. Additionally, rotation speeds greater than 500 rev/min are common for PCPs in shallow wells (3,000 ft). New developments in elastomers have allowed for greater cycles of deformation before fatigue.

ESPs. Continuous modifications, new designs, and new technologies have increased the motor capacity of ESPs used in the GSJB.


  • In mature fields, water control often is not an option. Producing water is necessary for producing oil.
  • Investment in treatment facilities, distribution, and injection is necessary.
  • Continued water balance and surveillance are important for improving oil production.
  • Continued artificial-lift cost analysis is required in mature fields.
  • EOR projects may be an option for improving the recovery factor, depending on the return on investment.
  • Teamwork between production, reservoir, and facilities engineering and production operations is necessary to develop and monitor waterflooding projects and to manage water distribution.
  • Improving the water-management process can increase asset value and extend the life of mature fields.

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 184931, “Water-Management Experience in Mature Basin in South Argentina,” by Clemente Marcelo Hirschfeldt, SPE, and Fernando Diego Bertomeu, SPE, Oil Production Consulting, prepared for the 2017 SPE Latin America and Caribbean Mature Fields Symposium, Salvador, Bahia, Brazil, 15–16 March. The paper has not been peer reviewed.