Operational Costs of Stimulating the Nisku Formation with Acid Reduced by One Half

Abstract Stimulation of carbonate oil and water producers with acid may result in an uneconomical increase in water production. This is the result of inefficient placement of the treatment stimulating the water-bearing rock preferentially to the oil. Typical treatments in the Nisku use selective tool isolation of zones to achieve the required placement control. The operational costs associated with this type of treatment make it difficult to perform economical acid stimulation treatments on marginal wells. A diverting material formed by the reaction of an aqueous solution of dibasic acids and rosin esters, with divalent cations, present in formation water, and spent acid allows the selective stimulation primarily of only oilproducing zones. The reaction product is an oil-soluble precipitant. The oil soluble nature of the diverter base materials and the resultant precipitate makes the likelihood of the precipitate forming in the oil zones remote; however, in the event of such a result, the produced oil will clean-up the precipitate. Several case histories from the Bashaw and Wayne areas of Alberta, Canada are presented to demonstrate that control of acid placement in water-cut producers, results in a significant increase of oil production while minimizing the impact on water cut. Usage of the abovementioned diverter resulted in a 50% reduction in the operational costs associated with acid stimulation. Introduction Acidizing has long been accepted as a means of increasing production from oil and gas wells. A major problem with many wells is the increased production of water along with the hydrocarbons1,2. The scenario is even more accentuated if placement control is not used during the stimulation treatment. Placement control methods vary around the world2,3,4. These methods involve use of diverting materials5, foams6, mechanical isolation or the use of varying injection rate7. The production of water is an added cost to the operator in the form of disposal, treating and/or the possibility of scale formation in the wellbore. For example, a 6m3/day increase in is approximately equivalent to a $2.50/day ($ Canadian) increase in operational costs. A 180m3/day increase would mean a $75/day increase. Therefore, the extra revenue from an increase in oil production could potentially be offset by the increase in operational expense of the additional water. The primary difficulty with treatments that have had the least amount of success has been the inability to place the acid where it will do the most good. A correlation can be made between unsuccessful stimulation treatments (in terms of water inflow increases), and the inability to effectively place acid. This paper is focused on treatments that were conducted in the Nisku formation in two separate fields in south central Alberta (Figure 1). BACKGROUND Nisku Formation Wayne area Nisku reservoir is a Devonian age dolomite. The Nisku dolomite is up to 60 meters thick in this area, with a particularly well developed porosity. The permeability in both areas ranges from 50 - 500 md and porosity is in the 10% range. The Nisku dolomite reservoir may be subdivided into the Camrose member overlain by the Nisku Open Marine member.

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