Matrix Stimulation Method for Horizontal Wells
Authors: Economides Michael J. , Ben-Naceur Kamel , Klem Richard C. 
Published: December 2007

Summary
Well-performance forecasts suggest that many horizontal wells could be good candidates for matrix stimulation, even in certain reservoirs where vertical wells should be stimulated only by hydraulic fracturing. This paper presents a technique for the matrix treatment of horizontal wells to allow uniform distribution of the stimulation fluids. It involves pumping a reactive fluid through coiled tubing and an inert fluid through the coiled-tubing/well annulus. The well is completed with either a slotted liner or a cemented and perforated casing. The coiled tubing, placed at the farthest end of the well is retrieved gradually at a rate dependent on the injection rate. Both rates are calculated and are contingent upon reservoir and well properties and upon desired stimulation-fluid coverage. The complex phenomenon of acid stimulation involves different rheological properties between acid and the inert fluid, simultaneous mass transfer and reaction kinetics, and for carbonate reservoirs, such instabilities as wormhole growth. Acid-volume distributions along the well are presented for cases with and without coiled tubing. This study details the procedures for this treatment, discusses hardware configurations, and outlines recommended fluids, additives, and rates.

Introduction
The emergence of drilling technology for highly deviated and horizontal wells created a new outlook in reservoir exploitation strategies. Some applications of horizontal wells, such as production from naturally fissured reservoirs1–5 or from reservoirs with gas- or water-coning problems,6–9 are obvious. In general, horizontal wells that are not hydraulically fractured are relatively more attractive than vertical wells if the vertical permeability is large or if the reservoir thickness is small. The requirement of good vertical permeability is relaxed in thinner formations.
If the wells are to be fractured, they can be drilled either in the expected direction of an induced hydraulic fracture or orthogonal direction to it.10 Criteria for the selection of well direction vis a vis the fracture direction were presented elsewhere.10,11
For the matrix stimulation of horizontal wells, the selection of candidates follows the same criteria as for vertical wells - i.e., expected posttreatment performance. Several investigators12–17 presented performance forecasts of fully completed horizontal wells.
While wells that are candidates for hydraulic fracturing must be cemented and cased for the appropriate zonal isolation and the spacing of the induced fractures (in the case of multiple fracturing), those that are to be matrix stimulated can be open holes, slotted liners, or preperforated liners. (Of course, they can also be cemented, cased, and perforated, if completion considerations are indicated.)
The use of coiled tubing is recommended for matrix stimulation of horizontal wells. This technique can provide a necessary mechanical isolation and diversion for uniform coverage along the horizontal well. For carbonate reservoirs (which could be excellent candidates for horizontal wells because they usually are fissured), injection of acid without coiled tubing can result in inadequate coverage and an unsuccessful stimulation.
Coiled tubing is pushed at the back end of the well, and the reactive stimulation fluid is pumped through the coiled tubing. Then the coiled tubing is withdrawn gradually at a rate of withdrawal contingent upon the stimulation-fluid injection rate and the desired volumetric coverage (Fig. 1).
An inert fluid may be pumped through the annulus formed between the coiled tubing and the well to provide the necessary backpressure. In such a case, the interface between reactive and inert fluids must be calculated to move and to be approximately at the same position as the injection point at the end of the coiled tubing. For this to occur, the inert-fluid injection rate must be reduced accordingly. Assuming that the pressure at the tail end of the coiled tubing is constant, then Equation 1
where iin=inert-fluid injection rate and x=length of the horizontal well where the tail of the coiled tubing is. Differentiating with respect to time and rearranging results in Equation 2
where dx/dt is exactly the coiled-tubing withdrawal rate. Thus, the inert-fluid injection rate must be reduced from an initial calculated value for the back end of the well by the reduction rate given in Eq. 2.