Screening and Coreflood Testing of Gel Foams To Control Excessive Gas Production in Oil Wells

Summary

Polymer-enhanced foam and gel-foam formulations were screened and tested for their injectability and gas-blocking ability in Berea sandstone cores and carbonate packs (in the presence and absence of oil at 85°C). Gel foams, with suitable gelation delay, were propagated through packed cores in a similar manner as polymer-enhanced foams (PEF's). However, the gas-blocking ability of cured gel foam was far superior to that of PEF. The gel foam blocked gas flow completely, even in the presence of oil, and a significant pressure differential had to be exceeded before the gas could channel through the gel foam and flow through the core.

Introduction

The use of foams for controlling an excessive gas/oil ratio (GOR) has been tested successfully in the North Sea^1,2 and in North America.^3,4 However, foams have a limited lifetime (weeks to months), and the treatment often needs to be repeated. A more permanent solution, with the same placement advantage, is to use gelling foams. During gelation processes the foam structure solidifies, imparting greater stability and increased gas-blocking ability to the gel foam.

The desired effect of a foam application in oil wells producing at a high GOR is to block the gas influx without hindering the oil production. Therefore, the gas-blocking capability of the foam is of utmost importance. A gel-foam application involves placing foam inside problem fractures, or high-permeability streaks, and allowing it to gel, thus generating a long-lasting barrier to gas flow. The optimal response to a gel-foam treatment should indicate incremental oil recovery at improved oil rates. Compared to regular foams, the advantage of gel foam lies in its better gas-blocking capability, greater effective lifetime, and larger residual resistance factor after gas has broken through the barrier. Thach et al.⁴ reported laboratory development and field application of PEF's in which the PEF's displayed high co-injection pressure with a strong resistance to gas flow. The effects lasted for more than a year in a hydraulically fractured production well. Dalland and Hanssen⁵ compared the gas-blocking efficiency of regular foams, PEF's, and gel foams and determined that improved blocking performance could be obtained through the addition of polymer. They found that gel foams were more persistent than PEF's but were not necessarily more efficient in gas blocking, and that placement of the gel foam was crucial to the success of the process. Having a relatively low density should allow gel foam to be placed above an oil-bearing zone, toward a gas cap. Furthermore, because it is difficult to propagate foams into areas with oil saturations above 30% owing to foam/oil interaction effects,⁶ a gel foam can be prevented from entering and damaging oil-producing zones during placement.

In addition to their use in GOR control, gel foams also have been applied recently to improve conformance in injection wells. Friedman et al.⁷ discuss the development and field application of gel foam to improve conformance in a CO₂ flood in the Rangely field. They describe a gel foam that resisted a 15 psi/ft pressure gradient. Miller and Fogler⁸ used glass micromodels to investigate the effectiveness of gel foams for profile modification during water injection. They also identified flow regimes in the gel-foam system that are relevant to our investigation and will be referred to later.

The objective of the present work has been to develop a near-wellbore blocking and diverting gel-foam treatment to combat gas channeling. The basic chemical components for a gel-foam system were identified and the gelation kinetics were investigated for reservoir applications at temperatures up to 90°C. The gelling system consists of a polyacrylamide polymer, with a carefully controlled degree of hydrolysis, coupled with chromium (III) complex crosslinkers. At elevated temperatures, depending on the size of the treatment, a 5- to 40-hour gelation delay is needed for proper placement of the gel foam in a reservoir. To optimize the polymer-crosslinker-surfactant combination, various PEF and gel-foam systems were investigated at reservoir conditions.

Experimental Section

Materials.

Brines.

Initial gelation experiments were carried out with a reservoir-injection brine having a total dissolved solids (TDS) content of 5 wt%. To isolate the effects of salinity and ionic strength on the gelation systems, two additional brines were used in bulk gel experiments: 5 wt% NaCl, and 2.7 wt% NaCl with 2.3 wt% CaCl₂. The first brine matched the TDS content of the reservoir injection brine, while the second brine matched both TDS and ionic strength.

Several corefloods were also carried out with a degassed, synthetic brine characterized by a TDS content of 2.1 wt%, which was prepared by dilution from a stock 21.0 wt% brine solution having the following composition: 172.45 g/1000 g NaCl, 9.40 g/1000 g MgCl₂:6H₂O, 43.00 g/1000 g CaCl₂:2H₂O, 2.15 g/1000 g Na₂SO₄:10H₂O.

After the selection of a target well location for the gel-foam application, subsequent experiments were carried out in 0.5 wt% NaCl.

Six surfactants and six partially hydrolyzed polyacrylamide (HPAM) polymers were evaluated for compatibility with the gel-foam system (Table 1). An oxygen scavenger, Na₂SO₃, was used at a concentration of 0.01 wt% to prevent the degradation of the polymer chains.

Chromium chloride was mixed with malonic acid (Ma) in molar ratios of 1:3 and 1:2 and heated to make chromium-malonate₃ (CrMa₃) and chromium-malonate₂ (CrMa₂) complexes, respectively. Commercial-grade chromium acetate (Cr Ac₃, 50% active) was also used as a chromium source.

Sodium malonate and sodium lactate were used as delaying ligands. Both were prepared by neutralizing the conjugate acid with NaOH, to pH 7.

The reservoir crude oil used had a dead-oil density of 0.86 g/cm3 and a viscosity of 10 mPa·s at 23°C.

Nitrogen gas was used in all PEF and gel-foam experiments.