No abstract

The downside of the conventional perforating method with explosive charges and guns is that it is risky. In addition to this, the method has a negative effect on the near wellbore permeability, and it creates mechanical damage. The impact stress associated with shaped charge and the outward travelling shock wave weakens the rock matrix, which increases the risk of sand production. Another negative impact of the shape charge is the creation of a low permeability zone, in which sand grains are forced toward the vicinity of the perforation chamber. For example, a perforation process with a 55% permeability reduction around the perforation tunnel led to 60% reduction in well productivity. An intended large underbalance differential pressure offers, to some extent, a solution to clean up the crushed zone. However, the de-bonded and weakened structure of the damaged zone is irreversible. The required surge pressure to clean up the perforations varies from 200 to 5,000 psi, because not all the perforations react the same way.On the other hand, built-in nozzles cause no damage to the formation, because no charge or shock is imposed to the formation. Furthermore, there is no longer an impact from underbalance or overbalance pressure differential between wellbore and formation. In this paper, we will introduce the engineering and mechanism of built-in casing (BIC) nozzles. With BIC, nozzles are activated from surface with deployment of specific activation tools. Once the tool engages with the targeted profile, the nozzles are opened and projected to the wellbore fluid. With circulation of cement-dissolving fluid, cement breaks and formation connection is initiated. Quantity and size of nozzles are engineered as per downhole production design criteria.In unconsolidated or poorly consolidated reservoirs, the strength of the rock structure should be evaluated to reduce the risk of sand production. Ultimately, the differential pressure shall be high enough to effectively clean the perforations, but not so high as to cause sand production.As mentioned above, there are a great deal of scenarios and variable parameters involved in perforation with shape charges that have to be taken into consideration to ensure an effectively performing set of perforations. Because such a study and remedial approaches are costly and not always guarantee results, an alternative method is to use BIC perforations.

Due to drilling economics, operators prefer extending the lateral section over drilling a new well. It presents a challenge to run casing strings to the target depth in wells where horizontal section is longer than the vertical section. Although alteration of casing weight or installation of liner may present as solutions, they are hardly economical compare to selective buoyancy methods. This paper aims to take an engineering approach on optimizingly palceing a buoyancy barrier which traps lighter fluid in the horizontal section for thepurpose of reducing friction. As seem to not have been presented in SPE conferences before, the aim of this paper is to engineeringly identify the optimum placement of the barrier, measure the efficiency improvement and identify the cases for which running a barrier is essential to run the casing string to the target depth. Operators usually run a torque and drag to measure the improvemet made by placing a barrier in kick off point. In this paper we intended to verify this practice and offer a simple rule of thumb method that can help an operator to decide on weather it is needed to run a barrier. Referred to in this paper as flotation collar, it is installed as part of the casing string. It employs a mechanical barrier that traps the air or lighter completion fluid in the mostly horizontal section and separates it from the heavier completion fluid in the mostly vertical section of the casing string. Identifying the best position of the barrier is important to achieve the maximum hook-load. In this paper, numerous cases are studied by gradually expanding the air section and monitoring the hook-load to identify the best position for which the hook-load is maximum. As per its physics, there is only one position of placement which results in the highest axial tensile force, also known as hook-load, when forces of gravity and friction engage. Placing the tool too high or too low in the string misuses the available tensile axial force and will not provide the best results. By using casing flotation tools as a barrier, a spectrum of thirty to eighty percent tensile improvement in the axial load are observed and more than fifty percent reduction of buckling effects in vertical section. For some cases, running a flotation tool was the only option to reach to the target depth with the casing string. Flotation tools in long string wells are the only economical alternative to changing casing weights or running liners when it is to completing wells with extended horizontal sections. A flow-chart is presented to help with simplifying the process of choosing a flotation tool and finding its best position of placement.

No abstract

Summary In difficult wellbores, the traditional method for deploying liners was to run drillpipe. The case studies discussed in this paper detail an alternative method to deploy liners in a single trip on the tieback string so the operator can reduce the overall costs of deployment. Previously, this was not often practical because the tieback string weight could not overcome the wellbore friction in horizontal applications. In each case, a flotation collar is required to ensure there is enough hookload for the deployment of the liner system. The flotation collars used are an interventionless design using a tempered glass barrier that shatters at a predetermined applied pressure. The glass debris is between 5 and 10 mm in diameter and can be easily circulated through the well without damaging downhole components. This is done commonly on a cemented liner and cemented monobore installations, but more rarely with openhole multistage completions. The authors of this paper have overseen thousands of cemented applications of this technology in Western Canada, the US onshore, Latin America, and the Middle East. For openhole multistage completions, the initial installation typically requires a ball drop activation tool at the bottom of the well to set the hydraulically activated equipment above. The effects of circulating the glass debris through one specific style of activation tool were investigated. Activation tools typically have a limited flow area and could prematurely close if the glass debris accumulates. Premature closing of the tool would leave drilling fluids in contact with the reservoir, potentially harming production. The testing was successfully completed, and the activation tool showed no signs of loading. This resulted in a full-scale trial in the field, where a 52-stage, openhole multistage fracturing liner was deployed using this technology. Through close collaboration with the operator, an acceptable procedure was established to safely circulate the glass debris and further limit the risk of prematurely closing the activation tool. This paper discusses the openhole and cemented multistage fracturing completion deployment challenges, laboratory testing, and field qualification trials for the single trip deployed system. It also highlights operational procedures and best practices when deploying the system in this fashion.