Solving Excessive Water Production in a Prolific Long Horizontal Open Hole Drilled in a Naturally Fractured Carbonate Reservoir

Abstract

The paper presents a case history of a successful operation that was performed to reduce excessive water production in a horizontal well drilled through a naturally fractured carbonate reservoir. Because the well was completed with a 940-m horizontal openhole section, there were two significant issues in the attempt to reduce water cut without the use of a workover rig. There was no practical means of selectively isolating sections of the open hole, and even if it could be achieved, the fractures producing water could not be identified and individually isolated. A treatment was performed employing a sealant that would set up only in presence of water and would remain fluid in anhydrous conditions. This sealant was placed using a coiled tubing unit (CTU) and then overdisplaced into the formation, into the natural fracture system. Before the treatment, this naturally flowing prolific oil producer would not flow because of the hydrostatic pressure from the excessive water cut (i.e., >60%). Following the treatment, the well flowed at approximately 20% water cut for a few days, stabilized at 40%, and has remained in natural flow since the treatment. This paper describes the philosophy behind the treatment design, the testing of the sealant, the placement procedure, subsequent well operations, and well performance. To re-establish this well into productive natural flow without the use of a workover rig was considered to be a significant success, and the long-lived effectiveness of the treatment has exceeded expectations. Introduction This case study is taken from a south Italy field that lies within a mountainous national park area and is currently classified as the largest producing onshore field in continental Europe. Wells in the field are also very high producing wells from a naturally fractured carbonate reservoir lying at approximately 3500 m total vertical depth (TVD). Permeability is difficult to predict because it is dependent on natural fracturing, which results in a wide range of production rates from individual wells. Because the field is in a national park, development is strictly controlled and wellsites limited to fit in with the environment; therefore most is made of the existing sites. Wells in the field have highly extended well profiles, and more recently, multi-lateral completions. The flow line system is also complex because it may need to cross several valleys to reach the production station; hence wellhead pressures are necessary to produce through the flow line system. Very strict governmental controls on the operations in the field help ensure that work is minimized to only what is absolutely essential to develop the resources. Planning to move a rig onto the wellsite is normally a long process to obtain the required authorizations, and particularly expensive because of the mountainous terrain. Against this background, rigless interventions and the use of coiled tubing (CT) in the field have become widespread. When a naturally flowing well suddenly starts producing excess water, and oil production is lost because the well is killed by increased hydrostatic pressure, there is an intense commercial driver to attempt to resolve the problem with a rigless intervention. This situation offers an opportunity to use newer techniques because the commercial benefits of a successful job make the amount of risk acceptable to an operator willing to resolve the problem. This scenario provides a rare opportunity to try untried methods and was the case in the job described in this paper. While the technology described here has been used in the industry since the early 1990s, no published cases of similar work were found in similar demanding well conditions, i.e., a horizontal well with no means of mechanical isolation and no identifiable water source. The technique, however, proved to be a commercial success in re-establishing production from the well and proved to be long-lasting.

Polymer Systems for Water Shutoff and Profile Modification: A Review Over the Last Decade

“…This amount increased to 249 million B/D in 2005 (Khatib 2007). Chemical methods include silicate (Grattoni et al 2001;Nasr-El-Din and Taylor 2005;Elewaut et al 2006;Al-Dhafeeri et al 2008;Boye et al 2011), resins (Seright et al 2003), cements, and polymer gels (Seright et al 2003;Sydansk 2007;Lightford et al 2008;Al-Muntasheri et al 2010). Water is also responsible for most of the corrosion and scale problems in the oil field (Donham 1991;Nasr-El-Din 2003;Merdhah and Yassin 2009;Al-Tolaihy and Bukhari 2010).…”

The History of Hydrocarbon-Based Ultrafine Cement Slurry System for Water Shutoff in Offshore Mexico

“…This system was developed in the early 1990s and has been used since then in southern Mexico, onshore operations. It was a development from diesel oil cement (DOC) that has been used both for curing lost circulation (Lewis et al 2008) in aquifers and for water control either in vertical and horizontal wells (Lightford et al 2008) and recently has been combined with relative permeability modifiers to improve its effectiveness under the presence of highly fractured formations (Castillo et al2012) It was one of the earliest products used for preventing excessive water production. Ultrafine hydrocarbon-based slurry and DOC work on the same principle: they do not hydrate until the cement comes into contact with water and therefore will not set (Fig.…”

Investigation of mud filtrate invasion using computational fluid dynamics

“…al. [14] recently presented a different technique to reduce water cut and improve oil production in a naturally fractured formation by filling up with a sealant using a coiled tubing (CT) unit in a horizontal wellbore. al.…”

“…al. 's [14] research. When the MOC system was applied to a wellsite where significant natural fractures existed, water cut decreased from 60% to 23% after 2 months and 40% after 14 months.…”

“…When the MOC system was applied to a wellsite where significant natural fractures existed, water cut decreased from 60% to 23% after 2 months and 40% after 14 months. Figure 2.4: Graphical illustration of the horizontal borehole situation [14] .…”