Horizontal well - 1H was drilled in a mature field in Croatia with an extended open hole interval and a high differential pressure. As a result, differential sticking has occurred when drilling the horizontal section. This was the first well to be drilled in that area with application of a drill-in fluid that included specially sized calcium carbonate bridging agent with a blend of viscosifying and filtration control polymers. To identify the best drill-in fluid composition for the horizontal section, three compositions were evaluated based on fluid-loss control and plugging properties, low-shear rheology (LSRV) and formation damage potential. Introduction Recently, drill-in fluids have become more widespread in their use primarily due to the increase of horizontal and multi-lateral drilling, the increase in open hole completion, and the potential for much higher fluid production after their use. They provide a good drilling performance in horizontal wells and, when combined with open hole completion technique, maximize the well productivity. Formation damage tends to be more significant in a horizontal or in an extended-reach well for a number of reasons1. If the fluid used for drilling and/or well completion is not compatible with the reservoir rock bad formation damage may occur. Removal of damage - if possible at all - may be a costly undertaking. Preventing it by adequate drill-in fluid may be a reasonable solution. The use of such fluid may cause minimum formation damage. That can result in substantially improved production. Most reservoirs are sensitive to any fluids other than those contained in them naturally or similar to them. Contemporary drill-in fluids aim at reaching that. A variety of fluids can be used as drill-in fluids, including water-, oil- and/or synthetic-base fluids. The selection of the most appropriate drill-in fluid depends on the type of formation to be drilled and on the completion method to be applied. Some formations tolerate a wider range of drill-in fluid composition than others do. Lower-permeability sand stones and depleted or unconsolidated sandstone reservoirs do not tolerate fluid and particle invasion without suffering extensive damage. In order to drill horizontal wells adequately, the use of properly designed drilling fluid is crucial for drilling success. Not only does the drilling fluid need to be inhibitive; it must also be capable of laying down an impermeable filter cake to seal off depleted/underpressured intervals. The key how best to apply any drill-in fluid is to match the fluid with the reservoir and the completion design. Reservoir Characteristics Reservoirs A1, A2 and A3 of the studied oil and gas field represent a single hydrodynamic unit. The reservoir rock is sandstone (thin, strongly shally sandstone, laminated with non-permeable shale and sandy shale). Principal properties of the reservoir are summarized in Table 1. Laboratory Tests Drill-in Fluid Evaluation. The key for exploit the advantage offered by a horizontal well and obtain the desired performance was minimizing damage to the formation caused by drilling because of the damage due to filtrate invasion into the formation can be significant. Drill-in Fluid Evaluation. The key for exploit the advantage offered by a horizontal well and obtain the desired performance was minimizing damage to the formation caused by drilling because of the damage due to filtrate invasion into the formation can be significant.

Lost circulation is defined as the uncontrolled flow of mud into a thief zone and presents one of the major risks associated with drilling. The complete prevention of lost circulation is impossible, but limiting circulation loss is possible if certain precautions are taken. Failure to minimize lost circulation can greatly increase the cost of drilling, as well as the risk of well loss. The risk of drilling a well in areas known to contain potential zones of lost circulation such as fractured, cavernous, or high permeability formations is a key factor in making a decision to approve or cancel a drilling project. The successful management of lost circulation should include identification of potential loss zones, optimization of drilling hydraulics, and remedial measures when lost circulation occures.

A stuck pipe is a common worldwide drilling problem in terms of time and financial cost. It causes significant increases in non-productive time and losses of millions of dollars each year in the petroleum industry. There are many factors affecting stuck pipe occurrence such as improper mud design, poor hole cleaning, differential pressure, key seating, balling up of bit, accumulation of cuttings, poor bottom hole assembly configuration, etc. The causes of a stuck pipe can be divided into two categories: (a) differential sticking and (b) mechanical sticking. Differential-pressure pipe sticking occurs when a portion of the drill string becomes embedded in a filter cake that forms on the wall of a permeable formation during drilling. Mechanical sticking is connected with key seating, formation-related wellbore instability, wellbore geometry (deviation and ledges), inadequate hole cleaning, junk in hole, collapsed casing, and cement related problems. Stuck pipe risk could be minimized by using available methodologies for stuck pipe prediction and avoiding based on available drilling parameters.

Exploration and production as one of the most important parts of the petroleum industry encounters different problems, usually resulting in nonproductive time and additional expenses. The most common and most expensive of them are related to wellbore instability and associated problems. Wellbore instability problems are usually related to drilling operation, but they can also appear during completion, workover, or the production stage of a certain well. The traditional solution for wellbore instability problems is composed from the early recognition of specific wellbore instability problems, the main cause identification and swift response. For more effective solution it is necessary to incorporate wellbore stability and risk assessment in the early phase of well design. This chapter gives one general overview of wellbore instability problems and their causes as well as an overview of actual approaches and methods in wellbore stability and risk assessment.

Lost circulation is defined as the uncontrolled flow of mud into a thief zone and presents one of the major risks associated with drilling. The complete prevention of lost circulation is impossible, but limiting circulation loss is possible if certain precautions are taken. Failure to minimize lost circulation can greatly increase the cost of drilling, as well as the risk of well loss. The risk of drilling a well in areas known to contain potential zones of lost circulation such as fractured, cavernous, or high permeability formations is a key factor in making a decision to approve or cancel a drilling project. The successful management of lost circulation should include identification of potential loss zones, optimization of drilling hydraulics, and remedial measures when lost circulation occures.