Summary

The removal of formation skin damage from carbonate reservoirs is ordinarily accomplished by stimulation with hydrochloric acid. Uniform coverage of the zone being treated during matrix acidizing stimulations of carbonate reservoirs is an accepted1 requirement for successful treatment. However, the task of achieving efficient diversion and uniform zonal coverage is often difficult because of permeability heterogeneity within the treated interval.

In this article we describe a technique that has been used successfully to divert treating fluids in carbonate formations.

Introduction

Effective placement of the stimulation fluids evenly across the zones being treated has always been a prime concern during matrix acidizing of carbonate formations. This problem is compounded when treating long perforated intervals, zonal heterogeneities or open hole intervals (especially in horizontal completions).

In this article we describe a technique that has been used with success in the U.A.E. to divert treating fluids in carbonate formations. Actual data from several wells, both vertical and horizontal, that have been treated in different fields are presented. The methodology of candidate well selection, treatment design, and execution is described along with documented pre- and post-stimulation treatment production log assessments that verify the success of the technique.

The diversion technique uses coiled tubing (CT) for fluid deployment and diversion of the treating fluid is accomplished by employing a temporarily activated crosslinked gelled acid system. The creation of the diverter gel structure is dependent on the pH of the fluid and dissipates upon spending of the acid.

The impact, in terms of improvements in injectivity or productivity, on the wells treated using this process over other types of diversion techniques used in the area, was significant and is documented.

Laboratory study data from carbonate core flow tests are also included to illustrate how the diversion process physically manifests itself and is used to substantiate the field successes that were encountered using this matrix diversion technique.

Diversion Technique
Coiled Tubing.

It is generally accepted that, where possible and economically viable, CT should be employed for the placement of matrix treatment fluids2 in both cased and openhole situations. Bull headed matrix stimulation of carbonate reservoirs tends to result in a nonuniform treatment.3 This is especially true when long, openhole sections are being treated.

Diverting Agent.

The effectiveness of using particulate diverters in carbonate formations has been questioned3 and it is not possible, in most instances, to use them in conjunction with CTs. Foam has been used with success in carbonate reservoirs4 for some time but requires, in most cases, that additional equipment be mobilized to the location for on-site generation of the foam. Consequently, a need arose for an effective matrix diverting agent for use in carbonate reservoirs that could be placed through CT where it was not anticipated to require nitrogen on location for post-treatment well lifting operations. A derivative of a fluid originally designed for controlling fluid loss in acid fracturing treatments was found suitable as such a diverting agent.5

The fluid in question was an acid-based system that develops a crosslinked gel structure as a function of changes in pH. Essentially, the system crosslinks at approximately pH 3 and forms a firm crosslinked structure. The crosslinked gel structure starts to break at around pH 4 as the acid continues to spend itself until the gel has a minimal final viscosity (Fig. 1). No particulate solids are employed in the system so there is negligible residual formation damage.

Combination.

The use of CT (to optimize fluid placement) together with the temporary crosslinked gelled acid system (as an effective diverting medium) suggested a viable technique to improve the diversion process when treating carbonate formations.

Field Experiences
Water Injector Application.
Description.

To attain water injection targets for an onshore field it was decided that a campaign of matrix acidizing treatments would have to be performed on selected wells. It was noticed that the injection rate of several well clusters had declined while still being supplied with water at the system header pressure of 2,000 psi. The water flood scheme was an inverted five-spot pattern and the carbonate formation being injected into had two main parts, designated zone A and zone B. There were typically two sets of perforations associated with zone A whereas zone B was perforated as a single layer. The reservoir formation is of the Lower Cretaceous period and is an oolitic limestone with several sublayers that are separated by thin stylolite barriers. There are marked contrasts in layer permeability and porosity. The average reservoir pressure is 3,100 psi and the depth of pay is 8,700 ft with a corresponding bottomhole static temperature of 245°F.

Some 19 vertical injector wells were identified as underperforming, delivering 42% less than the targeted total daily water injection rate for these clusters. These wells were candidates for matrix stimulation.

It had been previously established that there was typically a nonuniform injection profile between the two layers with zone B taking a greater amount of water. A more uniform injection profile was also sought for any stimulation treatment performed.

Pilot Study.

To optimize the effectiveness of the treatment in terms of injectivity improvement, keeping cost in mind, four pilot injector wells were treated with different techniques and different pumping service providers. The pilot wells were very similar to one another in construction and completion (vertical cased wells). However, the two zones, A and B, had different permeabilities of around 5 and 10 md, respectively. The injection profile of each pilot well was determined through production logs before and after performing the acidizing treatment on each well.

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