Mature fields

Best Practices for Waterflooding Optimization Improve Oil Recovery in Mature Fields

This paper presents technologies and best practices to improve oil recovery in mature fields through waterflooding optimization. These technologies have proved practical and cost-effective.


Most mature sandstone reservoirs feature natural aquifer drive, artificial water drive, or a combination of the two. These mature fields generally are characterized by high water cut and high recovery efficiency. This paper presents technologies and best practices to improve oil recovery in mature fields through waterflooding optimization. These technologies have proved practical and cost-effective.


Although chemical enhanced-oil-recovery (EOR) technologies such as polymer flood and alkali/surfactant/polymer (ASP) flood can improve oil recovery by 10 and 20%, for waterflooded sandstone reservoirs, respectively, they are expensive and are not applicable in most mature fields at a low oil price. A major problem for waterflooded fields is that, with increased water/oil ratio (WOR), the cost of processing produced fluid soars to exceed the breakeven mark. As a result, many wells are forced to be shut in; in some instances, the entire field may be suspended.

Waterflooding-Optimization Methods

The technologies discussed in this section are effective generally for multilayer, heterogeneous sandstone reservoirs with high permeability contrast.

Zonal Water Injection. This is the most widely applied water-injection-optimization technology. In a multilayered reservoir, early water encroachment along thief zones often occurs. During the mature stage, when the field produces at high water cut, commingled water injection usually leads to ineffective water cycling from the injectors, flowing preferentially through the high-permeability thief zones and back to the surface from the producers.

Using the same injecting wellbore, zonal water injection can enhance water-injection rate arbitrarily in low-permeability, low-production, and low-water-cut production zones while reducing the water-injection rate of medium-high permeability, high-water-cut production zones. Thus, the application of this technology can achieve the goal of expanding sweeping efficiency in order to improve oil recovery.

Changing the Direction of Fluid Flow. The basic principle is to change the originally fixed injection/production-fluid-flow direction to sweep the remaining oil in bypassed high-oil-saturation areas. This goal is achieved through converting injectors into producers or vice versa. In practice, some injectors are shut in while others are left inactive or regular conversion between injectors and producers is conducted in order to change fluid-flow direction, achieving expanded sweep efficiency.

Water Shutoff To Improve Areal Sweeping Volume. This application addresses the challenge of lateral heterogeneities resulting from the permeability contrast of various facies sands. This technique seeks to change the original areal waterflooding direction to constrain ineffective water injection by shutting in the high-fluid-production, high-water-cut wells. The change in liquid-flow direction will benefit the injected water turning to the poorly swept region or bypassed remaining oil to expand sweep volume, achieving the goal of improved ultimate recovery.

Subdividing the Injection/Production Unit. This application addresses the interlayer heterogeneity of multilayer reservoirs that has developed through the adoption of a commingled injection/production strategy. Because of the interlayer permeability contrast, the injected water swept the oil in the high-permeability interval preferentially, resulting in abundant oil remaining in the low-permeability-production interval. Subdivision of the injection/production unit groups the pay sand with similar reservoir properties and helps improve the adaptability of well spacing and the well pattern. To ensure its economic feasibility, the process should use all available shut-in wells.

Cyclical Water Injection. The basic mechanism of cyclical water injection is the manual establishment of pressure pulsing in order to change the shape, position, and size of the dead oil. The process is realized through alternatively opening or shutting in the injectors periodically, which makes full use of compressibility effects and capillary- and gravity-dominated crossflows. Cyclical injection has significant potential in heterogeneous reservoirs with permeability contrast with light, high-compressibility fluids. Field application of cyclical water injection indicates that additional oil recoveries in the range of 0.5–5% can be achieved with a significant reduction in water cut.

Evaluation Methods

One issue with these water-injection-optimization methods is how to assess the potential gains from such applications quantitatively. In conventional waterflooding applications, the quantification process relies on reservoir simulation based on reservoir characterization and modeling. However, geological modeling and history matching are time-­consuming, and subsurface uncertainties can have significant effects on the evaluation. Here, two practical, reliable methods are presented that are applied easily.

Waterdrive Performance Curve. For a mature, waterflooded field, the waterdrive performance curve is an effective method to predict estimated ultimate recovery. The prediction is based on linear or log-linear relationships between cumulative oil production and another of a range of variables, including cumulative water production, cumulative liquid production, WOR, and water cut. Several types of waterdrive performance curves exist; among the most widely applied of these are Type A and Type B. Equations used in these curve types are provided in the complete paper.

Tong’s Curve. Tong’s theoretical curve describes a certain relation between ultimate recovery factor (ER), recovery efficiency of stock tank oil initially in place (STOIIP) (R), and water cut (fw) of any waterdrive reservoir. The recovery characteristics of each reservoir are expressed by their different values of ER; therefore, the fw/R curves are different from one another. In Tong’s curve, ER is taken as the module, and a group of fw/R curves can be plotted on a normalized coordinate paper.

Basic conditions for application of Tong’s curve include the following:

  • Aquifer-drive or waterflooded reservoirs must be present.
  • Water cut vs. recovery-efficiency pattern cannot be identified until water cut reaches 25% or recovery efficiency of STOIIP reaches 10%.
  • Heavier oil generally follows rules of water-cut vs. recovery efficiency on the left of the Tong’s-curve template, while that of lighter or volatile oil is located to the right.

Tong’s curve is often used to estimate recovery factors by comparing field-production data with the theoretical relationship between water cut and recovery efficiency of STOIIP. If the waterdrive recovery factor of a reservoir can be calculated in the early production stage, estimation of the changes in water cut in response to changes in recovery during the later stages of production is possible. Conversely, estimating ultimate recovery is possible on the basis of the trend of water cut in response to the increase in oil-recovery efficiency from the reservoir.

Best-Practice Examples for Selected Methods

The complete paper contains best-­practice examples for all five waterflooding-optimization methods discussed previously; examples for two of these methods are provided here.

Zonal Water Injection. The sandstone reservoir in M Field consists of three flow units with average permeability varying from 50 to greater than 500 md. Well A had been producing solely from the low-permeability top pay sand. By comparison, Well B produced from all three pay sands (Fig. 1).

Fig. 1—Schematic of commingled water injection to three sand units.


Initially, commingled water injection was performed. By April 2005, Well B was producing at 253 BOPD, while the production rate of Well A was 116 BOPD, down from 471 BOPD in May of 2003. Integrated reservoir characterization and production-logging-tool analysis indicated that injected water entered the two medium- to high-permeability lower flow units mainly and had a negligible effect on Well A producing from the low-permeability top flow unit. The rapid production decline in Well A was the result of pressure depletion. On the basis of this analysis, the water injector was recompleted with a single-string adjustable eccentric water distributor. The technology enhanced water injection to the top flow unit while constraining injection to the lower two flow units. Both Well A and Well B responded to the injection adjustment immediately. By May 2006, production rates of Well A and Well B had reached 566 and 725 BOPD, respectively, a significant increase from the prezonal water-injection rates.

Changing the Direction of Fluid Flow. The T Block SII11-12 produces oil from a sandstone reservoir with a high permeability of 1600 md and contains a STOIIP of 30.8 million bbl. Its production has entered the mature stage with 54% recovery and 97.9% water cut.

A water-injection-optimization campaign was launched in 2009. The injection/production pattern was modified from line cutting to peripheral line injection, consisting of four producers and five injectors. The injection/production well spacing increased from 250 to 450 m.

The new well pattern led to a change in water-injection direction and helped expand sweep volume to recover interwell remaining oil and attic oil further. The water-injection-optimization activity resulted in a significant increase in production rate from 110 to 194 BOPD and a slight drop of water cut from 97.9 to 96.7%. Average production rate per well increased from 28 to 49 BOPD. Ultimate recovery factor increased from 58 to 68%.

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 186431, “Waterflooding Optimization: A Pragmatic and Cost-Effective Approach To Improve Oil Recovery From Mature Fields,” by X.G. Lu, SPE, and J. Xu, C&C Reservoirs, prepared for the 2017 SPE/IATMI Asia Pacific Oil and Gas Conference and Exhibition, Bali, Indonesia, 17–19 October. The paper has not been peer reviewed.