Abstract
Like any other business, return on investment (ROI) drives the decision-making processes in the oilfield. The "cut-cost" approach can only be successful when resulting production is adequate. Especially during the past few years, it has been observed that most North America operators using horizontal completions in low-perm oil or gas reservoirs have abandoned the "lowest-cost" approach in favor of a "maximize-production" mindset. Maximizing ROI requires operators to continually evaluate both cost and effectiveness of various completion and stimulation options. With low-to ultralow-perm reservoirs, it has been proven in many fields in North America that using a long lateral section combined with effective, controlled placement of large, multistage propped fracturing treatments can offer the best economic return. Often being combined with pad drilling, the trend continues to be using fewer wells while maximizing the volume of reservoir rock that is fracture stimulated within each completion.
There are two interrelated choices that can be combined in several ways to decide how best to complete a lateral section to achieve maximum benefit:
Assuming a solid liner is installed, should the operator cement, seal off the annulus into sections by some method, or leave it unsealed?
What method should be used to provide frac-stage isolation within the liner?
This paper will provide an overview of several different horizontal completion methods and stimulation techniques most commonly used in North America for low-perm reservoirs during the past few years. Included are two different operators' experiences with multiple application methods, but the common denominator is that they included multiwell overviews. Managing risk properly will usually be more than a "current-well" mentality and requires a more field-wide approach, including the cost of completion interruptions from unscheduled/unexpected events.
One case takes the comparisons through completion cost and all the way to ROI results, where all wells had more than six months of production. Another case illustrates a situation where the operator concluded that well production is more dependent on reservoir quality than on his choice for completion methods. This case includes more than 75 wells with six to nine fractured intervals per well, comparing not only costs for four methods, but also showing the representative cost variations or overruns.
Generally, once a drillsite has been chosen, the most important variable that can be affected is effectively placing individual hydraulic fractures at (and only at) preselected locations along the completed lateral section. Choosing the method to be used is best made before drilling the well, but might have to be revisited if formation properties are different than anticipated or drilling problems result in a wellbore the is a poor fit for the completion plan originally selected. Obtaining effective isolation of stimulation stages is often the primary goal required to achieving adequate production response and effective reservoir exploitation while managing the costs to achieve best ROI on a field-wide basis.
