Volume 3, Issue 1

Worldwide drilling activities are significantly raised by the oil industry due to the increased global demand of hydrocarbon. The addition of new and sophisticated equipment, tools, and technologies in drilling a well are adding more costs in terms of new technology and equipment. In contrast, the reduction of drilling time due to the addition of those facilities has significantly reduced the drilling costs. As a result, there is a cost analysis dilemma faced by the drilling industry. In addition, shale gas wells are drilled using drilling technology very similar to that used in the drilling of conventional hydrocarbon wells. This causes the drill bit to wear out which significantly reduces the net penetration rate with the longer trip time. This scenario causes new challenges for the estimation of shale drilling cost in general. The overall cost estimation and analysis creates new challenges and responsibilities for the industry people. Moreover, cost effective drilling is one of the focal points for the industry toward a successful and sustainable drilling because by definition, sustainability covers the parameter, cost. The lack of proper training in handling financial sustainability has caused tremendous frustration in the current energy management sector. While everyone seems to have a solution, it is increasingly becoming clear that these options are not moving our drilling environment to any sustainable state. This article evaluates current and historical drilling and completion costs of oil and gas wells. As a starting point, the general cost analysis concepts are discussed in detail to have a strong foundation on the drilling cost and time estimation. Field data are used to show the cost trends for various depths in calculating drilling cost and drilling time estimation. Also outlined is the significance of Authorization for Expenditure (AFE) in terms of variations of oil and gas prices, costs, and availability of major well components and services at particular locations. The new addition of some features in cost estimation will help in understanding the overall cost estimation. This article will enhance understanding of drilling cost analysis and will provide a guideline in preparing AFE.

In resistivity log analyses, it is common to correct “apparent resistivity” predictions for borehole, shoulder bed, wellbore mud and fluid invasion effects. While this is important, the use of apparent resistivities is often based on the assumption of a homogeneous isotropic background medium. This is generally not true in modern logging applications. While more sophisticated analyses are available to study anisotropy, many of the methods are proprietary and unpublished. In this paper, we illustrate how, using a new fully three-dimensional electromagnetic model (applicable to fiberglass or metal mandrels and larger-size transmitter and receiver coils in layered anisotropic media with dip), both R h and Rv resistivities can be straightforwardly predicted from standard tool measurements. Because both the model and application are new, we will review the underlying theory and numerical implementation before describing the detailed procedures developed to study MWD/LWD anisotropy.

Carbon sequestration is considered a promising method to mitigate the accumulation of greenhouse gases. Depleted oil and gas reservoirs are a desirable vessel for carbon sequestration. It is crucial to maintain the sealing ability of formations with high concentrations of CO 2 . Plugged wells are one of the risky leakage pathways and leakage defects the purpose of carbon sequestration. The performance of a plugged well must be monitored and evaluated through the whole lifetime of carbon sequestration. Much research is focused on well integrity assessment for carbon sequestration projects, however, a systematic manner addressing the CO 2 leakage risk of plugged wells has not been presented. This study will fill this gap. Cause and Effect Analysis (CEA) method and Failure Mode and Effects Analysis (FMEA) method are used in this paper. CEA is used to identify the causes of plugged wells leakage, while FMEA is used to evaluate the possibility that CO 2 will leak from plugged wells. WH field, a CO 2 EOR oil field located in the Gulf of Mexico, is studied as an example. CEA and FMEA are effective ways to evaluate the plugged wells leak risk in carbon sequestration activities. This analysis can also be used to assess the integrity of CO 2 injection wells and oil production wells of carbon sequestration projects. Through the use of CEA and FMEA, high risk plugged wells are identified.

The introduction of hydraulic fracturing as a new technology for shale gas production from low-permeability geologic formations has revitalized natural gas as an abundant, economic, and cleaner source of energy. However, hydraulic fracturing has raised several environmental concerns, from air pollution and drinking water contamination to on-site accidents and risks associated with potential seismic activities induced by subsurface fluid injection. Some of the potential incidents and accidents could be mitigated by adding more precautions to the different stages of an operation. Integrity of the injection well is one of the most important factors to be considered when dealing with water resources contamination. This work focuses on groundwater contamination potential in a leakage accident from the casing during hydraulic fracturing. A numerical flow and transport modeling approach is adopted to explore and quantify the associated risk of groundwater contamination under various hypothetical scenarios. The goal is to investigate a few cases with different geological and operational parameters and, also, to evaluate the importance of the well integrity, especially along the interval in which well casing is inside an aquifer. The results of the work show that if the well integrity is compromised, the groundwater will be contaminated by the chemicals in a relatively short duration. It is also shown that the result of the stochastic work is dependent on how well one knows the failure scenario. The appropriate choice of the probability distribution function for the leakage point is of high importance in simulations such as these.

Experimental difficulties and safety issues while working with H 2 S under acid gas exposure conditions (HPHT) have greatly limited the understanding of their impacts on wellbore integrity. To address this, an experimental study was designed to prepare and maintain H 2 S gas and H 2 S –containing fluids exposure experiments under relevant subsurface conditions. In this study, several cement formulations (Class H neat and pozzolan amended cements) were cured under subsurface (downhole) conditions and then exposed to H 2 S for a period of 28 days at a temperature of 50°C and pressure of 15 MPa. The cement was exposed to both an H 2 S saturated fluid and gaseous H 2 S to simulate existing wellbores that came into contact with an acid gas injection plume under reservoir conditions. The ensuing cement alteration products were determined by scanning electron microscopy, X-ray diffraction, and ICP-OES. The exposed cement underwent significant physical and chemical alteration via sulfate formation and decalcification. Both the neat and 35:65 pozzolan amended cement were decalcified with a complete loss of structural integrity, while the 65:35 pozzolan cement, although still intact, lost much of its integrity. The integrity of the exposed cement samples increased with an increasing pozzolan addition suggesting that pozzolan amended cements would be beneficial in wellbores expected to come in contact with H 2 S environments.