RESERVOIR ENGINEERING

Designing of A Waterflood For Spraberry Trend

Designing of A Waterflood For Spraberry Trend

The Spraberry Trend area has a stratigraphy mainly composed of sandstone, shales, siltstone and limestone. The mass of rock is divided into three distinct units: the Upper Spraberry, a sandy zone; the Middle Spraberry, a zone of shales and limestone; and the Lower Spraberry, a sandy zone. (Charles 2008) The Upper Spraberry unit occurs at an average depth of 7000 ft with a gross thickness of approximately 220 ft. It is composed of six stacked units (1U-6U). The individual beds rarely exceed 15 ft in thickness. Reservoir characterization demonstrated that the productive oil sands in the Upper Spraberry are from two thin intervals, the 1U and 5U, respectively. The reservoir rocks in the 1U and low porosity and permeability characterize 5U. (Slider 2010) Extensive sets of interconnected vertical fractures allow oil recovery from this low permeability sandstone.

The purpose of this study is to design a waterflood for Spraberry Trend through the application of horizontal well simulation scenarios conducted in the Humble waterflood pilot (Fig. 1). The reservoir model was developed and matched with the Humble pilot performance in the previous work by Putra, Kindem and Schechter (1996). (see appendix)

Horizontal Well Performance

Recent research on horizontal wells has focused increasingly on fractured reservoirs. One of the research objectives is to increase well productivity compared to that obtained with vertical wells. Due to its length, often much greater than a vertical well, a horizontal well can intercept many more fissures than a vertical well, thus obtaining higher productivity. (Charles 2008) The basic reservoir model used in this study is identical to the Humble pilot model. The reservoir parameters for the simulation of the horizontal well in this study were obtained after history-matching the Humble waterflood pilot. The simulation scenarios were conducted to evaluate the effects of different average pressures with different lengths of horizontal well sections on oil recovery. The simulations were performed using a constant plateau rate of 100 BOPD, no water injection, and running with 500 psi BHP for 10 years. These simulations were by no means optimized, but to illustrate the potential benefits associated with horizontal wells in the Spraberry oil province. Since the average pressure is unknown, the average reservoir pressure was varied from 1000 psia to 1500 psia with different lengths of horizontal well sections. The simulation result is shown in Fig. 2. (see appendix)

The Effects of Water Injection on the Performance of Vertical and Horizontal Wells

The effect of the vertical production well with and without the vertical injection well on the oil production rate is shown in Fig. 3. The initial oil rate of 12 bbls/day was produced with natural depletion and the average oil rate was only 8 bbls/day afterward. (see appendix)

The water was injected 1000 stbw/d per well from four vertical injection wells. At about 1.5 years after initiation, the water started to sweep oil to the production well until the production rate peaked at 50 ...