Formation Damage Caused by Wax Deposition Results in Shale Production Decline
Authors: Carpenter Chris 
Published: April 2023

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This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 210414, “First Evidence for Shale Production Decline as a Result of Formation Damage Caused by C60+ Paraffin Wax Deposition: A Permian Case Study,” by Amir Mahmoudkhani, SPE, Locus Fermentation Solutions, and Jonathan Rogers and Martin Shumway, SPE, Locus Bio-Energy Solutions, et al. The paper has not been peer reviewed.

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Analysis of production decline curves revealed that three candidate wells in West Texas depleted faster than indicated by a type decline curve, indicating a potentially abnormal permeability-reduction mechanism. A biosurfactant-based squeeze program was recommended and applied in three horizontal wells. The biosurfactant treatment offers an alternative and economical method for remediation of formation damage caused by high‑molecular‑weight paraffin wax deposition in porous media that does not require costly intervention techniques to apply.

Introduction
The Bone Springs horizontal oil play in the Delaware Basin spans from southeast New Mexico into West Texas. Stacked, multipay reservoirs, each with diverse rock properties, possess upside but also complexity. The initial targets in the play were conventional sandstones. Wells then tapped into carbonate lenses and, ultimately, low-permeability sandstones. As a result of horizontal drilling technology combined with hydraulic fracturing, very thin sands and other facies are now being produced. Generally, reservoir quality of this unconventional hydrocarbon system is controlled by carbonate content, where increased carbonate content typically is associated with lower productivity.

Experimental Methods
All crude oils exhibited precipitation of organics at ambient laboratory temperatures. Even after storing crudes at the bottomhole temperature of 140°F, a small amount of wax remained insoluble in bulk liquid.
Samples of formation drill cuttings were received for various depth intervals between 8,500 and 12,000 ft. X‑ray diffraction analyses of solids revealed quartz as the major mineral phase, with clays and carbonates account for remaining phases. Combined fractions with 160-micron size were used for microcolumn oil-recovery screening tests. Carbon distributions of oils and waxes were performed by high-temperature gas chromatography (HTGC).
The Du Noüy ring method was used to measure static surface tensions of biosurfactant solutions at different concentrations and was applied to calculate critical micelle concentrations at ambient temperature. Interfacial tension (IFT) measurements were performed using a drop-shaped tensiometer using the pendant-drop method. Finally, the IFTs of oil in synthetic formation water and in biosurfactant solutions prepared in city tap water were determined. Contact-angle measurements also were performed.
The wax-appearance temperature (WAT) of crude and wax samples was determined by the differential scanning calorimetry method. Spontaneous imbibition experiments were performed using the Amott-cell method at reservoir temperature. Berea sandstone core plugs (25×50 mm) with a permeability of 385 md and porosity of 18.4% were used. Core plugs were saturated with homogenized crude oil samples at 140°F for 7 days.