Formation Damage Caused by a Water Blockage Chemical: Prevention Through Operator Supported Test Programs
- H.A. Nasr-El-Din (Saudi Aramco) | J.D. Lynn (Saudi Aramco) | K.A. Al-Dossary (Saudi Aramco)
- Document ID
- Society of Petroleum Engineers
- International Symposium and Exhibition on Formation Damage Control, 20-21 February, Lafayette, Louisiana
- Publication Date
- Document Type
- Conference Paper
- 2002. Society of Petroleum Engineers
- 5.2 Reservoir Fluid Dynamics, 4.1.2 Separation and Treating, 2.5.2 Fracturing Materials (Fluids, Proppant), 1.8 Formation Damage, 1.8.5 Phase Trapping, 1.6.9 Coring, Fishing, 3 Production and Well Operations, 4.3.4 Scale, 1.6 Drilling Operations, 4.1.5 Processing Equipment, 5.8.7 Carbonate Reservoir, 4.6 Natural Gas
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Recently, a Saudi Arabian well producing out of a carbonate reservoir was squeezed with a scale control chemical (a phosphonate-based inhibitor). The target zone has a low permeability of nearly 20 mD. The treatment adversely affected oil production, and the damage was attributed to water blockage after the treatment. Several solvents that can remove water blockage were tested, including ethylene glycol monobutylether (EGMBE) and a proprietary chemical designated as E-2. The latter chemical is a patented blend of glycol ethers and has been proven successful in many field applications in the North Sea environment. The chemical is typically applied as a 15 percent by volume mixture in appropriate brines. On this occasion, however, the vendor recommended the chemical be squeezed "neat" into the formation. Concerns as to the effectiveness of the chemical as well as concerns about the cost caused the authors to question the use of the chemical "neat".
In house laboratory test programs demonstrated that using the "neat" E-2 chemical would have resulted in severe formation damage from two newly identified mechanisms. The first is precipitation of salts from the formation brine, and the second is the formation of a tight, stabilized emulsion with the native crude oil, possibly stabilized by the precipitated salts. These additional problems would have exacerbated the water blockage problem. The chemical E-2 precipitated salts even when it was co-mingled with the field mixing water. Phase separation of salts was noted at room temperature and reservoir temperature (200-220°F). By comparison, the use of the "neat" EGMBE did not result in precipitation of salts nor emulsion formation.
Core flood studies confirmed loss of oil production due to water blockage where relative permeability to oil deceased by nearly 50%. In addition, testing of the neat E-2 chemical showed a loss of approximately 85 percent of the original permeability of reservoir core samples, following treatment. This significant drop in relative permeability to oil was attributed to the formation of a tight emulsion stabilized by precipitated salts.
The use of the E-2 chemical at 15 percent concentration was compatible with the formation brine and the field mixing water. It also showed a significant recovery of permeability, however, the efficiency was no better than the EGMBE. Surface tension measurements, and water blockage studies all confirm the effectiveness of the E-2 chemical up to 15 volume percent. E-2 has not been shown to be a cost effective alterative in most applications on Saudi Arabian carbonates. In house evaluation of this chemical prevented extensive formation damage, and resulted in the development of a nondamaging and a cost effective treatment.
There has been evidence of loss of oil production due to water blockage problems in some oil wells in a carbonate reservoir in Saudi Arabia. Water blockage is generally the result of water trapping after drilling, workover, or stimulation operations in low permeability portions of a reservoir. It can be the result of local wettability alteration,1 and is exacerbated by low drawdowns in horizontal wells. Since water blocking is related to capillarity, and pore throat diameter, it is usually confined to the lower permeability portions of the reservoir. High surface area clays and micro-porosity are commonly associated with formation of water blocks, although this is a feature in silic-clastics,1 and not in carbonates, which are the focus of this study.
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