In the past estimating drilling performance or project performance for well engineering projects has been carried out in a combination of ways such as accounting for time based events that eventually result in costs or financial relationships. It is rather unfortunate, but the requirement within the industry still remains the quantification of projects and project costs as a function of cost or financial exposure. In most cases the situation is one of which inherent peculiarities within the project, though not man-made, are somewhat relegated to the background during project evaluation. Frequently this is due to the inability of project teams to quantify the parameters required to adequately establish key contributory factors responsible for overall project performance. In this paper I have tried to postulate a rather straight-forward method of establishing performance metrics without so much as deriving complex equations an engineer may find highly impossible or cumbersome to fully regularize to provide any meaningful relationship from one well to the other. The relationship model developed tries to relate both operational and financial efficiencies as a project/well specific performance factor referred to as TPI, i.e. the "Technical Performance Index". The TPI is specific to each well and a regional average provides an indication for overall performance. This paper does not consider completion operations or any operation related to well testing or workover operations at this moment but focuses primarilly on dry-hole operations up until the well is programmed for completions. Relationship ModelsSeveral parameters need to be qualified to be able to fully establish project performance metrics. As with every "practical" approach to representing/presenting data, the solution proferred must be in a useful and useable format, must be able to represent information in a comparative manner while maintaining objectivity from well to well and it needs to be a finite value, i.e. number that makes sense. Our approach will be similar to the concept proposed by Nkwocha 1 where he established directional drilling performance evaluation as a value between 0 and 1. Therefore the model for evaluating drilling events will need to follow the same format with contributions from technical and financial based workflow considerations. The contributory techno-financial based model looks at the ability of the equipment, personnel and tooling to adequately deliver the well objectives. The financial model on the other hand eliminates statistical models as these can be cumbersome and difficult to implement and interpret especially in the short term. However in the long-term statistical models become prevalent and obvious where a system of continuous improvement has been implemented as the only real basis for having statistical models in the first place. However, in this paper the actual financial exposure of each operation is quantified and is used as an input in the performance model. Why Do We Need A New Relationship Model?The drilling ind...

Cement plugs play a central role in providing hydraulic isolation for oil and gas well integrity. They are routinely required for abandonment purposes, drilling sidetracks and wellbore remedial operations. Despite extensive industry experience from around the world, there are many cases in high-pressure, high-temperature (HPHT) wells where an otherwise straightforward cement plug operation has led to major non-productive time (NPT) resulting in escalation of overall well costs. There are a number of issues that increase risks especially when it involves placement of high-density cement slurries in HPHT wells. Downhole conditions present additional challenges, which make it difficult to do the job right the first time. Whenever a job goes wrong in these conditions there is often an impact apart from the immediate non-productive rig time. In addition to the increase in costs there are other associated impact, e.g. potential loss of downhole barrier with negative implications for safety and the environment. Many studies and publications have highlighted the risk of unmitigated fluids contamination during placement as one of the most common causes of cement plug failure. One service company with extensive experience operating in the North Sea has used a model that integrates design and planning combined with a structured, detail-oriented process workflow to reduce surface execution and downhole placement risks thereby increasing the chances of success. The model relies heavily on close cooperation between the service company and the operator. Following the same strategy, this model can be applied in other geographical environments with the core objective of improving quality ensuring the job is always done right the first time. Some case histories, which inspire confidence in the ability to sustain the success rate, are described in this paper.

In 2013, PTTEP drilled a deepwater well in the Gulf of Martaban, Myanmar. The water depth was 1003m with riserless drilling over 1000m below seabed. Being exploration well without any reliable offset well, shallow hazards risk was high. Shallow hazards analysis was performed, showing the high risk of shallow water flow. Shallow water flow causes many incidents, including surface casing cement failure. It can happen during cementing, cement phase transitioning, and after the cement has set. Cementing with the shallow water flow presence is, therefore, the critical operation to achieve the well integrity. Using special cement systems, foam or ultra-lightweight, is expensive, logistically challenging, and operationally complicated. After thorough risk analysis and mitigation, conventional class G cement system was selected.Information from 12-1/4Љ pilot hole and actual 26Љ hole were analysed for cementing plan. Shallow water flow occurred at 1819m in pilot hole. Pump and dump was started from 1760m in 26Љ hole to prevent the flow. However, drilling to 2005m encountered another strong flow. So, the critical zone was identified from 2005m downward. For operational success, the critical zone was covered by gas tight tail slurry with API fluid loss control less than 50 mL/30 min, a SGSA transition timer shorter than 30 minutes and a short thickening time to prevent formation fluid migration. Lead slurry was designed for sufficient density and long thickening time to provide enough hydrostatic pressure, preventing fluid migration while tail slurry was setting. Not being ultra-lightweight cement, slurries were pumped with high excess and contain fibrous LCM to mitigate losses risk. Centralisation also contributed to the cementing success.During the cement job, good returns had been observed. No shallow water flow occurred during and after cementing. Operation was continued without subsidence issue.This paper summarises the process of assessing the risks and designing the economical cement operation to mitigate the risks, resulting in safe operation from shallow hazards.