CaCO 3 scaling tendency can differ over seawater flood life

Krishnam U. Raju
Saudi Aramco
Dhahran

Seawater can reduce the likelihood of scaling caused by a formation brine that has a high calcium carbonate (CaCO ₃) scaling potential.

Seawater is often injected into reservoirs for pressure maintenance and enhancing oil recovery.

Commingled with formation brine, the seawater lessens the CaCO₃ scaling potential of the mixture. As the percentage of seawater in the mixture increases, scaling potential decreases and may even become negative.

Once the scaling potential becomes negative, the produced water can dissolve CaCO₃ scale that may have formed in the flow lines. Therefore, a well that might have required squeezing with a scale inhibitor early in its production life may not require resqueezing, once the water composition changes.

The scaling potential decreases to zero as a result of the injected seawater.

Overall water quality is of major importance during the waterflooding of a reservoir. The water volume handled could be as much as ten times more than the oil volume produced. Other important factors in waterflooding are the planning, design, and operation of water handling systems.

Compatibility of injection water with formation brine is critical if scaling problems are to be avoided.

A major source for injected water is the sea. Seawater is often used for waterflooding throughout the world. However, it may pose a major problem if the formation brine has very high concentrations of calcium, strontium, and barium. The mixture of seawater and formation brine could cause sulfate scale.

But if calcium carbonate scaling potential exists in reservoirs, such as limestone, seawater injection may mitigate CaCO₃ scale. CaCO₃ equilibrium in presence of carbon dioxide (CO₂) gas can be represented by:

CaCO₃(solid) + CO₂ (gas) + H₂O(liquid) = Ca²⁺ + 2HCO₃^-

Seawater is usually saturated with CaCO₃ at surface conditions. However, seawater scaling potential is modest because of the presence of low calcium ion concentration compared to high-calcium formation brines, especially in carbonate reservoirs.

Scales form in producing wells and flow lines mainly because of decreases in pressure and the consequent release of dissolved CO₂ gas as the produced fluid moves from the reservoir through the wellhead, flow lines, and gas/oil separators.

Formation brine under reservoir conditions of high pressure (2,000 psi), with acidic gases like CO₂ and hydrogen sulfide (H₂S), is close to saturation with respect to CaCO₃.

During production, because of pressure decreases, these gases bubble out of the fluid and shift the equilibrium to the left. This results in a highly supersaturated CaCO₃ solution that starts to form scale on the surface of tubing and flow lines.

Seawater under reservoir conditions of high pressure with CO₂ gas is highly undersaturated with respect to CaCO₃. When seawater mixes with the formation brine, the scaling potential of the mixture becomes less than that of the original formation brine.

As the percentage of seawater in the mixture increases, the scaling potential decreases, as shown in Fig. 1a [110,496 bytes].

At some point the scaling potential of the water mixture can be negative. When this stage is reached, the produced water will dissolve calcium carbonate scale that may already be present in the flow lines.

An extension of this concept leads to the perspective that a well originally having scale can become nonscaling over time.

As an example, consider a situation where the original formation water has a high CaCO₃ scaling potential and the field pressure is being maintained by injecting a compatible water.

The production life of the well can be divided into three stages based on the scaling potential and scale growth. These stages are shown in Fig. 1.

Stage 1

During initial oil production (Stage 1), the water cut is very low resulting in minimal scale buildup. With time, however, the water cut normally increases as does the buildup of carbonate scale (Fig. 1b). This buildup is mainly due to the production of formation water. If scale growth does not interfere with oil production, then, there is no need to treat the well.

In many cases, however, the well must be acidized and/or squeezed with a scale inhibitor, at significant expense, in order to maintain reasonable production rates. These treatments usually have a limited life, and retreatment is required when the scale again significantly reduces oil production.

Stage 2

As the waterflood continues (Stage 2), the formation brine becomes diluted by the injected water. Consequently, the scaling potential of the produced water decreases. When the potential reaches zero (Fig. 1a), no further scaling is observed (Fig. 1b).

Stage 3

In the later stages of waterflooding (Stage 3), the scaling potential of the produced water can be negative (Fig. 1a). Once this point is reached, the produced water will begin to dissolve calcium carbonate scale that may already be present in the system (Fig. 1b).

Although this concept is based on CaCO₃ scaling, the same perspective can be generalized for other scales formed in the oil industry.

Once a well is identified as a severe scaling well, typical treatments include squeezing the well with a suitable scale inhibitor at regular intervals throughout its producing life. These treatments are a significant cost that may not be required after Stage 1.

Scale treatment

Periodic visual inspection of the well and evaluation of produced water scaling potential should be continued until Stage 2 is reached.

Scale-prediction models could help minimize actual field inspections if the predictions have been proven reliable. Once Stage 2 is reached, scaling problems for a well should be over and it will no longer need squeeze treatments.

Acknowledgments

The author would like to acknowledge the support of the management of Labs Research and Development Center and Saudi Aramco for permission to publish this article.

The Author