Evaluation of a pH-Sensitive Polymer for Gravel-Packing Operations
- Hamoud A. Al-Anazi (Saudi Aramco) | Mukul M. Sharma (U. of Texas at Austin)
- Document ID
- Society of Petroleum Engineers
- SPE Drilling & Completion
- Publication Date
- March 2002
- Document Type
- Journal Paper
- 27 - 35
- 2002. Society of Petroleum Engineers
- 5.4.10 Microbial Methods, 5.2 Reservoir Fluid Dynamics, 1.6.9 Coring, Fishing, 2.7.1 Completion Fluids, 4.3.1 Hydrates, 3.2.4 Acidising, 4.1.2 Separation and Treating, 4.2.3 Materials and Corrosion, 2.4.5 Gravel pack design & evaluation, 1.6 Drilling Operations, 1.8 Formation Damage
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Rheological data is presented for a type of polyacrylic acid polymer as a function of polymer concentration, pH, shear rate, and temperature. It was found that the viscosity of the polymer is strongly dependent on the pH of the solution. Compatibility tests showed that the polymer was compatible with most brines (NaCl, NH4Cl, and KCl) used for field applications. Core-flow results indicated that the filtration rate was low compared to that of hydroxethylcellusose (HEC). Our evaluation study shows that this anionic polymer would be an excellent nondamaging carrier fluid for gravel packing. It has excellent rheological and suspension properties and is easily broken down with a mild acid wash before flowback.
Polyelectrolytes dissociate in solution and form macroions, which interact with counter ions in the solution. The interaction forces between these ions give polyelectrolytes their characteristic properties. They have been widely used for several applications (drug delivery, adhesion, paints, chemical valves, etc.). The swelling properties of polyelectrolytes are strongly dependent upon pH, ionic strength, and polymer concentrations.1-3 The influence of these factors on the swelling of polyelectrolytes is summarized in Ref. 4. Weak polyelectrolytes ionize over a limited pH range.5 Examples of strong and weak polyelectrolytes are polystyrene sulfonic and polyacrylic acids, respectively. Polyacrylic acid and its copolymers are classified as polyelectrolytes, which stretch and form uncoiled chains when ionized because of the repulsive forces between carboxylic groups. This behavior increases the viscosity of the polymer chains upon ionization.6
The objectives of this paper are to evaluate pH-sensitive polymers as a carrier fluid for gravel-packing operations; to investigate the rheological properties of the polymer solution by studying the effect of pH, salts, polymer concentration, and temperature; to assess the effectiveness of the polymer solution through core-flow tests and compare it with a conventional carrier fluid used for gravel packing; and to understand the interactions of polymer molecules with ions present in formation fluids.
The viscosity of polymer solutions was measured as a function of shear rates with a rotational viscometer (Model Fann 35*). The viscosity of the polymer solution was measured as a function of pH at different shear rates (3, 6, 100, 200, 300, and 600 rpm). The solution temperature was controlled with a double-wall circulating cup connected to an external heating bath. The polymer solution (350 mL) was placed into the sample cup. The pH of the solution was raised slightly by adding an NaOH (1.0 mole/L) solution. The viscosity was measured at each incremental increase in pH until it reached a value greater than 12. Hydrochloric acid (10wt%) was then used to gradually decrease the pH of the gelling solution, and the viscosity was measured after each incremental drop in the pH value. The effect of temperature on the polymer solution's rheological properties was investigated by changing the solution temperature while other parameters (concentration and pH) were kept constant. The viscosity was measured as a function of shear rate at a given temperature. The examined temperature range was 20 to 80°C.
Core-flow experiments were conducted with Berea sandstone cores. Two types of apparatus were used for core-flow experiments - a modified API high-temperature/high-pressure (HTHP) filtration cell and a core holder. A schematic diagram of the API cell setup is shown in Fig. 1. The dimensions of the core used for the modified API cell are 6.35 cm in diameter and 2.56 cm in length. The core was first saturated in a vacuum with 3wt% NaCl brine for more than 48 hours. The core was then loaded into the modified API cell, where 3wt% NaCl brine was flowed through the core from the bottom to the top at a flow rate of 4 mL/min until the brine permeability became constant. The polymer solution was then placed in the cell, and the pH was adjusted to the desired value by adding NaOH solution. An overbalance pressure of 100 psi was applied to the polymer with nitrogen gas. The fluid-loss rate was monitored as a function of time at a constant applied overbalance pressure. Brine injection was resumed in the reverse direction to remove the filter cake and to measure the stabilized return permeability.
The filter cake was removed from the core face after disassembling the cell. After that, an acid (10wt% HCl+0.5 vol% corrosion inhibitor) was injected from the top and soaked into the core for 1 hour. The final return permeability was measured by flowing brine in the reverse direction to assess the potential of permeability loss caused by polymer treatment. Core-flow experiments were also performed with a Hassler sleeve core holder on Berea cores with a length of 6.0 in. and a diameter of 1.0 in. In this type of experiment, the API filtration cell was replaced with a Hassler sleeve core holder** in the setup shown in Fig. 1. Three pressure taps were along the core to measure the pressure drops across different sections. The brine permeability was measured at a flow rate of 4 cm3/min, with the flow going from Section 3 to Section 1. The polymer and acid were injected at Section 1. This means that Section 1 represents the formation closest to the wellbore. The experimental procedure was the same as that described previously.
The polymer solution was prepared in several brines, including NaCl, NH4Cl, KCl, CaCl2, and synthetic reservoir brine (TDS = 18,892 mg/L). The pH of the polymer solution was raised by adding an alkaline (NaOH or KOH) solution. The compatibility with each brine solution was investigated by adding brine to the gelled polymer (at a volume ratio of 1:1). The effect of multivalent cations (Ca2+, Mg2+, Al3+, and Fe2+) on the polymer properties was also examined. After adding the brine, any change in the volume of the gelled polymer was monitored as a function of time to assess the swelling or shrinking of the polymer.
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