RIASSUNTO
Summary
An oil field in central Saudi Arabia produces super-light crude from a sandstone reservoir. The formation contains up to 7.0 wt% authigenic clays dominated by kaolinite and illite/montmorillonite mixed layer clays. To mitigate sand production and improve well productivity, a frac pack stimulation treatment was conducted on most producing wells in this field. The treatment introduced several fluids, which might invade the formation and induce formation damage.
An experimental study was conducted to determine potential formation damage due to fines migration and clay swelling, and to design an effective clay stabilizer treatment. The work included performing coreflood experiments using reservoir cores under reservoir conditions. The critical salt concentration (defined, as the salt concentration below which there is loss of permeability) was first determined. Several commercial clay stabilizers, cationic polymers, were evaluated. The effects of stabilizer type, concentration and acids on core permeability were investigated in detail.
The experimental results indicated that the critical salt concentration (KCl brine) was nearly 5 wt%. Severe loss of permeability was observed when brines of lower salt concentrations were injected into reservoir cores. The effectiveness of clay stabilizers was found to be a function of chemical type and concentration. Some of the chemicals caused loss of injectivity at higher concentrations. It was found that these chemicals did not readily dissolve in water and formed fish eyes. When these chemicals were injected into reservoir cores, they formed an external filter cake, which caused loss of permeability. Good mixing of the stabilizer and proper filtration solved this problem. Hydrochloric acid at 15 wt% did improve the performance of at least one of the clay stabilizers examined.
Based on lab testing, a cost effective clay stabilizer was tested in the field. Field results indicated that the chemical did not cause loss of injectivity, and minimized formation damage due to fines migration and clay swelling.
Introduction
Sandstone formations contain varying amounts of clay minerals and fine particles, which are attached to sand grains by weak van der Waal attraction forces. Naturally occurring clay minerals are generally present in an agglomerated or flocculated state. It is well known that injection of low salinity fluids will disturb the equilibrium state between clay particles and the matrix sand grains. As a result, these fine particles will disperse and cause severe loss of permeability. Many investigators have examined factors affecting permeability decline due to fines migration and clay swelling, including: salinity changes,1-5 and flow rate.6 The effect of heavy brines used in completion operations on permeability changes was also investigated.7-9
Clay minerals are negatively charged at pH values greater than 5.10 The negative charges on the clay minerals make them sensi-tive to fluids and provide the mechanism by which clay stabilizers operate. Several chemical treatments are available to mitigate formation damage due to fines migration and clay swelling. A thorough review of these treatments was given by Zhou et al.10 According to their work, clay stabilizers can be divided into the following classes: simple inorganic salts, cationic inorganic polymers, cationic organic polymers, anionic organic polymers and nonionic organic polymers. Zhou et al. discussed the advantages and disadvantages of each class of clay stabilizer.
Clay stabilizers are commonly used in acidizing and fracturing treatments. They should be thermally stable under reservoir pressure and temperature. They must be chemically stable in acids used for stimulation, and in the high pH environment encountered in fracturing treatments. In addition, clay stabilizers must meet the following criteria to effectively stabilize fine particles in low permeability sandstone reservoirs:11
They must resist wash-off by fluids flowing through the reservoir rock such as brine and oil.
They should be nonwetting on sandstone surfaces to reduce water saturation.
They must have a low, uniform molecular weight to prevent plugging of pore channels, especially in low permeability formations.
They must have positive charges (cationic) to neutralize the negative charges of clay particles.
Cationic organic polymers have functional groups of positive polarity. They adsorb onto the clay surfaces at multiple sites.11,12 The adsorbed polymer with multiple attachment to the rock surface will resist exchange with other cations in solution. This will increase the lifetime of the clay stabilization treatment.
Cationic organic polymers have been shown to be excellent clay stabilizers.13-15 Therefore, the present study will address this class of chemicals only.
To mitigate sanding problems and enhance oil production in the subject sandstone field, several producing wells were stimulated using a fracturing treatment.16 The treatment entails flooding the formation with various fluids, which would subject the formation to changes in pH and ionic strength.17
The objectives of the present study are to:
determine the potential for formation damage due to fines migration and clay swelling,
assess the effectiveness of various clay stabilizers, and
determine propagation and flow characteristics of these chemicals in natural reservoir cores.
Experimental Studies
Materials.
The potassium chloride and ammonium chloride products used were American Chemical Society grade chemicals. Distilled water with a total dissolved solids (TDS) of less than 2 mg/L and a resistivity greater than 18.3 M?·cm at room temperature was used to prepare all solutions. Potassium and ammonium chloride brines were filtered before they were used in the coreflood experiments.