Drilling activity in most operations in Russia is a "controlled" schedule of events. This makes the management of change process extremely difficult and challenging should the fundamental well design conditions fail or are no longer applicable. With little or no planned contingencies, recovery is usually difficult with unplanned events. For turnkey projects the general contractor is expected to to bear the cost for unforeseen events if these are not identified within the "project book". The use of technical institutes for drilling related field development planning is a thorough process culminating in what is normally referred to as the "Project Book". However, the quality of the final product as with all roles requiring a level of expertise, is limited to the experience and competency of all contributors to the planning document. This is due to a combination of factors: The absence of contractors at the field developing planning stage to challenge concepts and provide more realistic operational limitations;Poor risk identification and mitigation process at the planning stage leading to loss of efficiencies and financial loss;A reactive approach to project delivery;Poor planning or a lack of it;Lack of leadership or ownership through the project life-cycle; andUndue interference from project stake-holders. Project books are developed by institutes contracted by the operating companies. These project books are documented evidence that technical, health, safety and environmental considerations are accounted for to meet the requirements of the government. These documents are thorough and carefully formaulated. However, the lack of input from the field to project books makes contingency planning difficult to implement and sometimes and impossible consideration. Project books contain details of equipment and technologies to be deployed for each project. In most places if a plan becomes unattainable a management of change process may be required to adopt changes to ensure success. For most projects in Russia this is not the case. The general contractor model has been here a long time and there is no illusion of change apparent. It is a convenient way of doing business with advantages and disadvantages as well. One major advantage removes the bureaucracy of permits and licenses to operate specific types of equipment from the operator. It ultimately makes one company solely responsible for well delivery and all (or most) contractual relationships with sub-contractors. It transfers the risks associated with the project to the general contractor, thus making them liable. For the general contractor, disadvantages are not limited to liabilities. Since contingency planning is not within the scope of the project books, it tends to create bottlenecks especially where it is not captured during risk assessment and subsequently in the compensation matrix. Furthermore, the process of decision making and ensuring client acceptance for compensation for costs related to unforeseen events, is rather cumbersome. The very same bureaucracy that is an advantage comes into play as each event is followed up by a series of carefully worded letters of correspondence with a stay of action on a matter until an official response is received. A typical approach in the West may need an email communication to the client as sufficient notification demanding immediate response for the operation to carry on.. This paper looks at some of the events over the cause of the last one year and their eventual impact to both the client and the contractor. Impact assessment to client/contractor can be quantified in monetary terms, inefficiencies and profitability as well as an estimate of the cost of not meeting production quota/schedules and the overall project delivery objectives.
Casing and liner running and cementing operations in high angle wells with long open hole sections pose seemingly diverse sets of challenges irrespective of location and drilling environment. The fluvial loose formations predominant in the arctic region of Russia and most parts of Siberia provides more than adequate tests and constraints to modelling, understanding and accommodating the risks associated with such operations as this. This is further complicated with no reliable nor consistent information regarding representative geo-mechanics models or failure plains within the region.This paper looks at modelling casing 1,2,3,4 running operations and the impact of perceived friction factors and choice of accessories on the overall out come of the operation. The objective is to better understand the modelling constraints and the importance of certain parameters and assumptions in the final solutions. Successes, failures and lessons learned will be articulated to provide key best practices or design considerations for similar or future projects. Furthermore, we will also evaluate the technologies available within the area and the impact of technology adoption on both the ability to land casing/liner and provide adequate cementing.
Earlier attempts to establish DD performance using the directional drilling difficulty Index (DDI) proposed by Oag & Williams1 is flawed and difficult to interpret. The philosophy behind the DDI relationship is based on the perception of a sample space. Thereafter a mathematical relationship between the "perceived" variables identified within the sample space was proposed. DDI can only be applied for performance benchmarking if the planned DDI can be related to the actual DDI. DDI can only be used to compare the difficulty of drilling wells from the same terrain and to similar vertical depths. Since DDI does not consider adherence to the plan to account for differences between plan and actual drilled paths it therefore does not provide much information in the way of performance monitoring or benchmarking. Is there a need for directional drilling performance monitoring? Is it possible to isolate other methods of measuring performance such as finance or time based relationships? Are we able to demonstrate directional drilling performance in such a way it becomes possible to eliminate the impact of differences and variations in service prices, service tiers, competency of rig crew and rig capability, terrain, etc? This makes the cost based approach quite restrictive in its application in establishing a key performance indicator for directional drilling activities. Traditional methods2 for measuring performance use metrics such as cost/foot, cost/10000 metres or feet, NPT distribution, ratio of NPT-to-Exposure time for specific services, $/BOe and days on well to name but a few. Generally, the metrics are designed either as time or cost based relationships. The implication there of is that directional drilling competency or performance is somewhat lost within the generalized approach this method requires where information is normalized into time or cost based variations. Therefore, directional drilling impact on the drilling cycle becomes a measure of how quickly the well is drilled with little or no consideration on how to get there and the impact of the tortuous part drilled on the outcome and performance of the well. This paper does not suggest the elimination of traditional methods but looks at ways of establishing a performance metric between the values 0 and 1 that can be used to compare directional drilling performance whilst still capturing the essence of time and cost based relationships. Furthermore, this method becomes extremely easy to use and can be easily computed at the well site using a simple spread sheet solution as the inputs for each well can be obtained from the standard directional survey file and the daily drilling reports. The application of the results include benchmarking performance from well-to-well, across projects, contractors and fields and to understand the influence of directional driller competency and geology on the final performance indicator. Introduction Directional well surveys are defined by the following:Surface location usually expressed in terms of a geographical or UTM co-ordinatesA subsurface target which is also defined by specific co-ordinates which are usually not the same as the surface location unless in specific cases. This is also further defined in terms of a target tolerance around a specific vertical depth reference.The standoff between the surface location and the subsurface target(s) usually establishes the DLS (or BUR in case of a 2D well) requirement, the directional well path which includes inclination and azimuthal variations and the sail angle through the target(s).
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...
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