An Alternative Solution to Sandstone Acidizing Using a Nonacid-Based Fluid System with Fines-Migration Control

Abstract

The Caballos formation is thick laminated sandstone with less than 10% of total clays and permeability ranging from 20 mD to as high as one Darcy. However, the production from this formation is often limited due to the low critical flow rate in the matrix (less than 1 mL/min) and associated fines migration as shown in several tests. Historically matrix acidizing and hydraulic fracturing treatments in this formation have only been partially successful due to destabilization of the clays and inadequate fines stabilization, along with the incompatibility of the crude oil with many conventional acid systems. In order to overcome the limitations associated with the use of conventional acid systems an extensive laboratory study was conducted using a non-acid based stimulation fluid. The base fluid selected was a newly developed chelating agent that is very tolerant to high concentrations of both carbonate and aluminosilicates, and iron and zeolite bearing minerals. By including acid salts in the fluid it proved possible to develop a fluid system with the equivalent dissolving power of a conventional 6:1.5 (HCl: HF) mud acid, even at temperatures as low as 180°F. Testing also showed that the fluid was capable of controlling fines migration and that a scale inhibitor could be included in the formulation, while the fluid system exhibited excellent compatibility with the formation fluids throughout the field. The newly developed non-acid fluid system provides some unique advantages for matrix acidizing applications and in particular for stimulating the Caballos formation 1) Minimizes the risk of secondary and tertiary precipitation due to the nature of the chelating agent 2) A single treating fluid instead of the multiple fluids/stages used in a conventional treatment 3) Greatly reduced sludging and emulsion tendencies compared to conventional acid systems (without the addition of surfactants or demulsifiers) and much lower corrosion rates 4) The ability to stabilize fines present in the matrix 5) Allows for a scale inhibitor to be included in the treating fluid 6) Reduces the logistics and HSE risks during the execution of the treatment. This paper reviews the laboratory testing including an extensive core flow testing performed to develop a new nonacid treating fluid for both matrix acidizing and dual stimulation applications in the Caballos formation and its implementation in the field, illustrated with case studies and production data. Introduction In the Orito field in the south of Colombia the most prolific reservoir is the Caballos Formation, 250-ft thick interbedded fluvial/deltaic and marginal marine sands that originally contained more than 700 million bbl of oil in place. Due to distinct changes in the vertical lithology the reservoir is divided into four distinct flow units or layers A, B, C and D in ascending order shown in Fig 1. Furthermore, the production of the wells along with a petrographic and petrophysical study has shown that there are two distinct zones of markedly different reservoir quality. The lower zone - layer A, is a much better quality reservoir than the upper zone. Layer A is a well sorted sand with kaolinite present in the pore spaces. The porosity and klinkenberg permeability varies from 12 to 14 % and from 100 to 300 mD, respectively. While, the upper zone - layers B, C and D - is a much poorer quality reservoir. A single facies of poorly sorted and loosely packed quartz with kaolinite in the inter-granular spaces. The porosity in this upper zone is predominantly intergranular ranging from 11 to 12 % and the klinkenberg permeability from 5 to 150 mD, (Fig. 2). In addition, due to the presence of a number of major and minor faults the reservoir is compartmentalized. The complexity of the stratigraphy reflected in the marked changes in the quality of the reservoir and the properties of the oil in place, across the field. Due to the fractional composition of the oil, the properties of the crude oil also vary between the different layers, independently of the location of the wells on the structure.

Zeta-Potential Investigation and Experimental Study of Nanoparticles Deposited on Rock Surface To Reduce Fines Migration

“…Acidizing (Huang et al 2002;Hibbeler et al 2003;Rozo et al 2007;Byrne et al 2009), a chemical stabilizer such as cationic or water-soluble polymers and ionic clay stabilizer (McLaughlin and Weaver 1982;Sharma 1996;Nguyen et al 2005), a coating with oil (Sharma 1996), and a zeta-potential-altering system (Kakadjian et al 2007) are some examples of suggested remediation techniques for this problem.…”

A novel approach for using silica nanoparticles in a proppant pack to fixate coal fines

“…Several applications like water flood displacement (Yuan and Moghanloo 2018;Bahraminejad et al 2019;Najimi et al 2019), fines fixation (Huang et al 2010b;Assef et al 2014;Yuan 2017;Zheng et al 2018), and enhanced oil recovery (Yousefvand and Jafari 2015;Bera and Belhaj 2016;Yuan and Wood 2018;Asl et al 2020) have been studied and experimented upon in this capacity. The use of nanoparticles to control fines release and fix them at or near the source of their origin has been studied comprehensively in both sandstones (Kia et al 1987;Mohan and Fogler 1997;Rozo et al 2007;Zeinijahromi et al 2012;Bin et al 2016;Hasannejada et al 2017) and carbonates Al-Anssari et al 2016;Al-Anssari et al 2017b;Al-Anssari et al 2018). The behavior of Coal Bed Methane (CBM) reservoir fines with nanoparticles, which are considerably different from sandstone fines, has yet to be comprehensively explored.…”