The aims of this study were to design a cost-effective stimulation treatment to remove formation damage from water injectors in a recently developed sandstone field in Saudi Arabia and enhance well injectivity, while maintaining formation integrity. This paper examines the design of the treatment, field monitoring, and analysis of acid returns. Core flow experiments were performed to screen various acid formulations, and evaluate acid additives.
The designed treatment was applied on several water injectors. Acid returns were analyzed to evaluate the effectiveness of each treatment. It was found that a preflush of 5wt% NH4Cl solution was effective in displacing potassium and sodium ions from feldspars and clay minerals compared to a preflush that contained hydrochloric acid only. A multi-stage treatment was designed to remove formation damage encountered in several water injectors in this field. The treatment significantly improved the injectivity index of the treated wells.
A newly developed field produces oil from sandstone formations in the Central Saudi Arabia. Water injection is used to maintain reservoir pressure and sweep oil. The first water injection wells completion was started in March of 1997. The injection water was supplied from an aquifer that has variable water quality and sulfate-reducing bacteria (SRB) related problems. These bacteria produce biomass and iron sulfide which cause significant loss of the injectivity1,2.
Based on our experience in a nearby sandstone field, water injection wells in this new field may be damaged due to SRB activities or invasion of drilling and completion fluids. Also, low water injection rates can be encountered in some wells which have low permeability. Various acid formulas are available for acidizing purposes and each formula can be used under a certain range of reservoir conditions. Therefore, the objectives of this study were to:
design a cost effective stimulation treatment to remove formation damage, and
enhance the injectivity into low permeability zones.
Coreflood experiments were conducted using reservoir rocks and conditions. Core plugs were selected from three wells in this field. The injection water was synthesized in the lab according to the chemical composition given in Table 1. Various acids were used including: three formulas of HCl acid (Acid-I, Acid-II, and modified Acid-II), and a retarded HF acid based on aluminum chloride. The formulas of these acids are given in Table 2.
In each coreflood experiment, the core was first loaded into a Hassler sleeve core holder at an overburden pressure of 2,500 psig and a temperature of 188°F (reservoir temperature). The core was subjected to vacuum for an hour. Then, it was saturated with injection water until the brine permeability became constant (±10%). The acid was injected into the core and followed with injection water as a postflush, until the core permeability stabilized. Then, the brine injection was changed to the reverse direction to simulate the injection well when it is put on backflow cycle. The injection rate was tested at 2 and 4 ml/min. The injection mode was changed to the forward direction to assess the potential of permeability loss due to acid treatment. A new core plug was used in each experiment.
The concentrations of key ions in the core effluent were measured. Calcium, magnesium, sodium, potassium, aluminum, silicon, and total iron ions were analyzed by Induced Coupled Plasma Emission Spectrometry (ICP). Sulfate ion in the aqueous phase was measured turbidimetrically following precipitation with a barium chloride solution (0.1N). The detection limit is nearly 20 ppm and precision is ±5%. The concentration of hydrochloric acid was measured (±5%) by acid/base titration using 0.1 N NaOH solution. X-Ray Powder Diffraction (XRD) and was used to identify the crystalline material of the particulate solids collected in the core effluent during coreflood experiments and in acid returns. XRD analysis was also used to identify the bulk mineralogy of field cores.