Chemical Equilibrium Models: Their Use in Simulating the Injection of Incompatible Waters

Abstract

Summary. One of the problems encountered in waterflooding projects is scale formation caused by chemical incompatibility between potential injection waters and reservoir brine. Chemical compatibility evaluation through laboratory experiments on cores at reservoir conditions is of limited value because only first-contact phenomena are reproduced. A numerical model is presented that couples a reservoir-fluid-flow/ thermal-equilibrium simulator with a chemical-equilibrium computer code. This model, AGIPS, enables us to calculate the evolution in time of the amount of scale formed at any point in the reservoir and inside the wells when changes occur in the temperature of the injected water and when the injection water mixes with reservoir brine. Moreover, the model calculates temperature and pressure profiles in the reservoir, together with their evolution in time, taking into account the permeability reduction caused by scale formation. Results are presented for the chemical-equilibrium code validation by matching experimental data on scale formation in mixtures of incompatible waters. An example is also given of the use of AGIPS in simulating a five-spot waterflood where incompatible water is injected. Introduction Water injection to improve oil recovery is a long-standing practice in the oil industry. Pressure maintenance by water injection in the early stages of field exploitation or secondary recovery by peripheral and pattern waterflooding both call for huge amounts of water to be injected into oil reservoirs. The selection of the injection water is a crucial factor when waterflood operations are planned. In offshore oil fields, the most obvious (and the cheapest) source of water is the sea; in onshore fields, waters from shallow aquifers are normally used for injection. River water is used only when no other source is available because of the high content of suspended matter and micro-organisms usually present. In all cases, the prerequisite for good injection water is present. In all cases, the prerequisite for good injection water is that it must not impair well injectivity and reservoir fluid characteristics. Injection water must be free of suspended particles, organic matter, oxygen, and acid gases (CO2 and H2S) before it is pumped into the injection wells. pumped into the injection wells. Fine inorganic particles in the injected water may form a cake at the well bottom and plug the injection well. Algae and other living organisms may grow at reservoir level, forming a gelatinous body that impairs injectivity. Backwashing and acid washing are the usual well treatments adopted when these troubles occur. Bacteria introduced into the reservoir in the injection water may grow and travel through the formation and may metabolize both formation oil and brine. Although microbial EOR is being considered as a potential process for improving oil recovery, people in the industry still consider the introduction of bacteria into an oil reservoir a source of trouble. This is particularly true when sulfate-reducing bacteria are present in the injection water because they metabolize the reservoir brine, forming H2S. The continuous or batch addition of bacteria-killing chemicals is a must in every injection process. The presence of oxygen and acid gases in the injection water causes corrosion in both surface and well equipment, jeopardizing the safe operation of this equipment. Moreover, corrosion scale transported in the injection water may accumulate at the well bottom and plug it. Degassing the injection water under vacuum or stripping with hydrocarbon gases is common practice in the oil industry. Once the water enters the oil-bearing formation, two more problems arise: compatibility of the injection water with the reservoir rock and with the reservoir brine. Reservoir rocks often contain shales, dispersed in the pores, finely interlaminated, or interbedded in the pay. The shales are in equilibrium with the reservoir brine: any change in the ionic strength (as a first approximation, in the salinity) of the environment induces a rearrangement of the shale particles. If the salinity of the injection water is higher than that of the reservoir brine, the shale structure collapses. Shale lamellae are thus freed, and while they move about in the injection water they may plug parts of the formation, usually the most permeable parts. This plug parts of the formation, usually the most permeable parts. This may result in a reduction of rock heterogeneity and therefore in an improvement in oil displacement. When the salinity of the injection water is lower than that of the reservoir brine, the shale structure swells. This causes a reduction in the permeability of the (less permeable) shaly layers of the reservoir rock and thus an increase in the heterogeneity of rock permeability. As a consequence, oil recovery is impaired. Moreover, the injected water may dissolve minerals present in the reservoir rock. As a consequence, the composition of the injected water is changed, and this may affect its compatibility with the reservoir brine. A more controversial question is whether injection water should be totally compatible with reservoir brine (i.e., the formation of any insoluble matter, or scale, when the injection water mixes with reservoir brine should be considered unacceptable) or whether a certain degree of incompatibility can be tolerated. This point will be discussed in detail later. Scale Formation Along the Injection-Water Path in Waterflood Operations Injection water temperature at the injection wellhead is usually much lower than reservoir temperature. As it travels down the injection wellstring, the water cools the surrounding formations, and its temperature and pressure increase. If the water is saturated at surface conditions with salts whose solubility decreases with increasing temperatures (e.g. anydrite), scale may form along the wellstring. SPERE P. 288