Abstract

The demand for hydrocarbon production increases each year as world population continues to grow and more energy is consumed. This increasing demand has caused the oil and gas industry not only to develop new technology but also to develop reservoirs that were previously overlooked. These marginal reservoirs were deemed uneconomic, primarily because they typically existed on the outer fringes of known reservoirs or the potential productive formations were subject to excessive water production.

Many of these previously-overlooked reservoirs need to be hydraulically stimulated to make them economic. When using fracture stimulation to complete a wellbore in marginal reservoirs, it is not uncommon to produce excessive amounts of water. This excessive water production can come from the producing formation, water-wet formations which bound the producing interval, or lack of sufficient barriers between the productive zone and nearby water-bearing zones.

Because wells drilled in these marginal reservoirs are economically borderline, any additional water production resulting from the completion of these wells jeopardizes the already questionable economics. Consequently, the operators run a much higher economic risk when completing wells in these marginal reservoirs.

This paper describes a case history using a relative permeability modifier (RPM) incorporated into a hydraulic fracture stimulation treatment to reduce excessive water production. By implementing this process, it gives the operator an additional tool to increase the chances of producing formations containing hydrocarbons which had been previously overlooked. Therefore, this process can help reduce the higher economic risk of completing marginal reservoirs. Incorporating this technique into a fracture stimulation treatment resulted in the best producing well in the study area.

Introduction

With the world's demand for additional hydrocarbon production increasing every year, more marginal reservoirs are being explored. These reservoirs were overlooked in the past because of their potential for excessive water production after hydraulic stimulation treatments. Since the beginning of the modern oil and gas industry, water production has been a problem that has plagued operators. It can cost as much, if not more, to produce a barrel of water as it does to produce additional hydrocarbons. Water production can also lead to additional costly problems such as scale, corrosions, production fines, etc. (Dalrymple et al. 1998). Water production, regardless of the reason, can hinder and in some cases result in complete loss of hydrocarbon production. If no action is taken once the water production occurs, the problem typically worsens before it becomes better. The industry has dealt with this by separating the produced water from the hydrocarbons, then disposing of it. There are more regulations each year regarding the handling and disposing of produced water, which continually increases the cost of handling this water.

Another method used within the industry is squeezing portions of the wellbore with a plugging agent, usually cement, to reduce or stop water production. Care must be taken when using a plugging agent to reduce water production because if the product is not placed in the proper area of the reservoir, it can shut off hydrocarbon production and water production. Also, depending on the product used, depth penetration can be limited to near-wellbore, which sometimes results in a temporary fix.

Anything that can reduce or stop water production benefits the operator and the industry. This paper will describe a process used on hydraulic stimulation treatments of wells that helps reduce the risk of producing excessive water. This process uses a RPM as a spacer introduced at the beginning of a hydraulic stimulation treatment that helps minimize the risk of producing excessive water.

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