Permeability is one of the most important characteristics of hydrocarbon bearing formations. An accurate knowledge of permeability gives petroleum engineers a tool for efficiently managing the production process of a field. It is also one of the most important pieces of information in the design and management of enhanced recovery operations. Formation permeability is often measured in the laboratory from cores or evaluated from well test data. Core analysis and well test data, however, are only available from a few wells in afield. On the other hand, almost all wells are logged. In this study an artificial neural network has been designed that is able to predict the permeability of the formations using the data provided by geophysical well logs with good accuracy. Artificial neural network, a biologically inspired computing method, with its ability to learn, self-adjust, and be trained provide a powerful tool to solve problems that involve pattern recognition. Using well logs to predict permeability has been attempted in the past. The problems with previous approaches were mainly two fold, namely, the number of variables used (only one variable-porosity), and using regression analysis as the main tool for correlations. The approach introduced in this paper is an attempt to overcome these short comings. This is done, first, by using many variables from well logs that may provide information about the permeability. Second, by recognizing the existence of possible patterns between these variables and formation permeability using artificial neural networks. Neuralnets are analog, inherently parallel and distributive systems. These characteristics, which will be discussed in the paper, are the main characteristics that enable artificial neural networks to be successful in predicting the permeability in rocks using well log information. Introduction Acquiring knowledge on formation permeability has remained one of the fundamental challenges to petroleum engineers.

The stability of asphaltenes is a critical parameter which may affect the flow in porous media significantly. This study investigates the change in the stability of asphaltenes after the interaction of asphaltenes originated from five different reservoirs with reservoir components? namely sand, clay, water, and brine. Asphaltenes are polar like water and brine. Hence, the initial lab-scale sensitivity studies were carried out first with asphaltene-water and asphaltene-brine systems. Then, the impact of porous medium has been investigated on asphaltene stability? asphaltenes are mixed with either sand or sand+clay mixture and then exposed to water or brine. Since, both sand and clay show water-wet behavior, the effect of water-wet rock surface on asphaltene stability has been aimed to understand. Moreover, different brine types and concentrations on asphaltene stability have been tested. A divalent and a monovalent salts were used to prepare brine solutions at 2%, 4%, 6%, and 8% concentrations. All laboratory tests were achieved under optical microscope and the interaction has been examined overtime. Our experimental results suggest that asphaltenes from all five crude oil samples are dispersed in water and they aligned themselves within water due to polar nature of asphaltenes and water. In asphaltene-brine systems, the monovalent salt (NaCl) interacts more with asphaltenes than divalent salt (CaCl2). This is due to higher water uptake capacity of CaCl2 than NaCl. The microscopic images revealed that a water layer is formed around CaCl2 inhibits the direct interaction of asphaltene-CaCl2. This behavior is enhanced within the porous media; salt crystals form bridges between the sand grains, clay and asphaltenes contribute to the formation of those bridges. The impact of brine has been observed more significantly at high concentration of the brine solutions. The asphaltenes-brine interaction also shows variations among different asphaltenes. Thus, all asphaltene samples have been analyzed for their elemental compositions to check if cation exchange is possible between the salts and asphaltenes. These experiments revealed that for the asphaltenes rich in calcium and sodium content, their interaction with brine is greater than for the asphaltenes poor in calcium and sodium content. Moreover, this interaction contributes to the formation of bigger asphaltene clusters which decreases the asphaltene stability and promotes more asphaltene precipitation. This study provides some general trends observed in asphaltene-water and asphaltene-brine systems and explains the reasons why some outliers do not fit the trends by examining the differences in the chemical composition of asphaltenes. Hence, this study enriches our knowledge towards asphaltene behavior in porous media.

Objective of this study is to shed light to critical well control parameters of horizontal shale gas wells drilled with oil based muds (OBM). This study utilizes an interactive well control simulator to re-evaluate the kick control procedures in water based mud (WBM) and verify its application to oil based mud. Due to gas solubility in OBM a real time drilling and hydraulics data analysis is essential to minimize kick volumes. Therefore, early kick detection and surface warning signs are critical to minimize the influx size and reduce wellbore pressures. Moreover, the impacts of water-to-oil ratio, gas solubility, kick size, influx type and circulation rates on well control are investigated. OBM kick control process in horizontal wells creates additional challenges since the surface pressure and volume are not representative of the bottom-hole conditions. In unconventional shale gas reservoirs, oil and synthetic based drilling fluids are very common. Drilling cost, log interpretation, and environmental impacts are the main drawbacks of OBM. However, wellbore stability, reduction in torque and drag, stability of mud properties at higher temperatures and better drilling performance are the main advantages of OBM. Preliminary results show that dissolved gas in oil is liberated at the bubble point pressure and complicates surface kick handling procedures. Choke adjustment is hard due to the unexpected high volume of gases released and the delay time of choke response. Early detection is a key factor in minimizing the influx size and properly controls the casing shoe and choke pressures. Based on 110 hours of real time interactive simulation, influence of gas solubility on well control in OBM is presented to improve rig and personnel safety and reduce the blowout associated risks.

Challenges associated with Utica and Marcellus shale well integrity and safety necessities further study in order to have an effective and economic drilling operations. Objectives of this comparative study are to evaluate the impact of unscheduled well control events on wellbore integrity, as well as the influence of poor drilling practices that trigger well control emergencies in shale gas wells. A realistic multiphase simulator is used to evaluate well control unexpected scenarios in Utica and Marcellus shales. Changing operational parameters such as wellbore profile, well control method, drilling fluid type and circulation rate in Marcellus and Utica horizontal wells are investigated. Further, this research studied the impact of influx type, size and intensity on well integrity. Behavior of dry gas, rich condensate and black oil influxes are compared in extended lateral wells. The impact of free gas migration in inclined downward laterals drilled with water based mud is compared to the influence of gas solubility in inclined upward wells drilled using synthetic oil based mud. Preliminary results show that deeper, over-pressurized Utica shale presents more challenges compared to Marcellus shale wells. When oil based muds are used additional challenges are presented since the surface pressures and volumes are not representative of the bottom-hole conditions. Dissolved gas in oil is liberated at the bubble point pressure complicating surface kick handling procedures. Gas influx migrates and reaches surface much quicker in water based muds and inclined downward laterals. Higher the influx circulation rate, size and intensity, higher the resultant pressures and volumes and higher the risk of exceeding casing shoe fracture pressure and risking well integrity. Drilling fluid type, properties and flow characteristics are critical for well integrity. Early detection is a key factor in minimizing kick size and properly contain pressures without violating safety and environment regulations and reduces the blowout associated risks. Accordingly, well integrity is verified by monitoring surface choke, casing shoe and constant bottomhole pressures throughout the entire well control operations.

Unconventional shale resources are drilled horizontally following the geologic bed dip upward or downward and completed with multi-stage fracturing to maximize reservoir contact. A recent study in Oklahoma claimed that toe-up (inclined upward) laterals yield the highest production rate and estimated ultimate recovery. The objective of this study is to investigate drilling fluid hydraulics and well control operations in toe-up laterals and compare the results to toe-down laterals. This study uses a multiphase steady-state hydraulics and a dynamic well control simulator. A hydraulics model was developed and verified with a data from a recently drilled Marcellus shale lateral in Monongalia County, WV in 2015. Static and dynamic pressure profiles were examined at drilling flow rate and at slow pump rate. Further, this research studies gas kick behavior and well control practices for kicks experienced at shallow, middle, and deep zones in the lateral section. Additionally, it considers the impact of operational parameters and influx characteristics on wellbore integrity. The results of this study showed that the developed hydraulics model successfully predicted the pump pressure with an accuracy of 0.97. Larger kick sizes result in higher pit gain, gas flow rate, choke, and casing shoe pressures in toe-down laterals. In contrast, in toe-up laterals, the higher the kick size, the longer the circulation times with an insignificant impact on the choke and shoe pressures. In toe-up laterals, gas bubbles migrated towards the toe and accumulated in high side pockets. Likewise, choke experienced less pressure, volume, and gas discharge rate for extended periods of time in toe-up laterals. Therefore, higher circulation rates and longer circulation times were essential to flush out the dispersed and trapped gas bubbles. The closer the kick location to the vertical section of the well, the shorter the circulation time needed. However, kicks experienced at the heel resulted in higher pit gain, gas discharge rate, choke pressure, and consequently high casing shoe pressure. Identifying the consequences of drilling toe-up laterals on hydraulics and well control is crucial for drilling operations. This improves rig and personnel safety and reduces the blowout associated risks. Accordingly, it is critical to verify the well integrity by monitoring surface choke, casing shoe, and constant bottomhole pressures throughout the entire well control operations.

Several techniques for hydraulically fracturing design were conducted in the liquid-rich Eagle Ford developments. This study shows that different results were observed due to the variation of geomechanical stresses of the rock across a play and reservoir properties. An optimum treatment for a liquids-rich objective is much different than that for a gas shale primarily due to the multiphase flow and higher viscosities encountered. This paper presents a treatment workflow that has been used with liquids-rich window of the Eagle Ford Shale. Review and integration of data from multiple sets across the play were used as input to a 3D hydraulic fracture simulator to model key fracture parameters which control production enhancement. These results were then used with production analysis and forecast, well optimization, and economic model to compare which treatment designs yield the best placement of proppant to deliver both high initial production and long term ultimate recoveries. A key focus for this workflow was to maximize proppant transport to achieve a continuous - optimum conductive - fracture half length. Often, due to the complexity of unconventional deposition, it is difficult to maintain complete connectivity of a proppant pack back to the wellbore. As a result, much of the potential of the fracture network is lost. Understanding the interaction of a hydraulic fracture and the rock fabric helps with the design of this behavior to achieve best results. These results can then be used for determining optimum well spacing to effectively develop a selected reservoir acreage. Currently, there are numerous wells and over two years of production history in much of the Eagle Ford. Comparison of these production results demonstrate the importance of employing a diligent workflow to integrate the sciences so that a proper understanding and application of hydraulic fracturing modeling can be achieved.

No abstract