bluuebunny/crossref_metadata_2025_split huggingface dataset:
Advances in Understanding Wettability of Tight and Shale Gas Formations
Authors: Lan Qing , Xu Mingxiang , Dehghanpour Hassan , Wood James 
Published: October 2014

Abstract
This paper aims at understanding the factors controlling the wettability of unconventional rocks. In the first part, we report the results of comparative imbibition experiments on several binary core plugs from the Montney tight gas formation, which is an enormous tight gas fairway in the Western Canadian Sedimentary Basin. Both contact angle and imbibition data indicate that the formation is strongly oil-wet. However, the ratio between oil and water imbibition rate of these samples is higher than what capillary-driven imbibition models predict. This discrepancy can be explained by the strong adsorption of oil on the surface of a well-connected organic pore network that is partly coated by pyrobitumen. We also define a wettability index by using the equilibrium imbibed volume of oil and water in binary plugs. Oil wettability index is in general positively correlated to the total organic carbon (TOC), measured by the Rock-Eval technique. In the second part, we report similar imbibition experiments on several binary core samples collected from the cores drilled in the shale members of the Horn River Basin. In contrast to the Montney (MT) samples, the Horn River (HR) samples imbibe significantly more water than oil. This observation contradicts the contact angle results which suggest that the HR samples are strongly oil-wet. Clay hydration, imbibition-induced microfractures, depositional lamination, and osmotic potential are collectively responsible for the excess water uptake. We also measure and compare spontaneous imbibition of oil and water into the crushed packs of the similar HR samples. Interestingly, in contrast to the intact samples, the crushed samples consistently imbibe more oil than water. The comparative study suggests that the connected pore network of the intact HR samples is water-wet while the majority of rock including poorly connected pores is oil-wet.
Overall, the results suggest that the well-connected pore network of the MT samples is dominantly hydrophobic and is very likely to be coated by pyrobitumen. This is the main reason why these samples imbibe more oil than water. On the other hand, the well-connected pore network of the HR samples is strongly hydrophilic primarily due to the presence of clay minerals and precipitated salt crystals coating the rock grains.
Assessment of Hydrocarbon Saturation in Organic-Rich Source Rocks using Combined Interpretation of Dielectric and Electrical Resistivity Measurements
Authors: Chen Huangye , Heidari Zoya 
Published: October 2014

Abstract
Complex pore geometry and composition as well as heterogeneous and anisotropic behavior of organic-rich source rocks significantly affects physical properties of the rock measured by well logs such as electrical resistivity and dielectric permittivity. These physical properties are used to estimate in situ petrophysical properties of the formation such as hydrocarbon saturation. Conventional methods for assessment of hydrocarbon saturation include interpretation of (a) electrical resistivity logs through resistivity-porosity-saturation models (e.g., Archie's equation and the dual-water model) and (b) dielectric permittivity measurements using volumetric techniques such as the Complex Refractive Index Model (CRIM). In the application of these approaches to formations with complex pore structure and mineral composition such as organic-rich formations, the impact of complex pore-structure (e.g., kerogen porosity and inter-granular pores), pyrite, and conductive mature kerogen have not been taken into account. The aforementioned limitations cause significant uncertainty in estimates of water saturation.
The method proposed in this paper improves the assessment of hydrocarbon saturation using combined interpretation of dielectric and electrical resistivity measurements. We start with pore-scale numerical simulations of electrical resistivity and dielectric permittivity of fluid-bearing porous media to investigate the impact of structure of pore and matrix constituents on these measurements. The inputs to these simulators are three-dimensional (3D) pore-scale rock images. We then introduce an analytical model that combines conductivity and permittivity measurements for assessment of water-filled porosity and hydrocarbon saturation. We applied the new method on actual sandstone and synthetic organic-rich source rock samples. We observed an improvement in estimates of water-filled porosity compared to conventional methods in both cases of conventional and unconventional rock samples. This improvement was more significant in the case of organic-rich source rocks with complex pore structure. In the case of synthetic organic-rich source rock samples, the simulation results confirmed that not only the pore structure, but also spatial distribution and tortuosity of water, kerogen, and pyrite networks, affect the dielectric permittivity and electrical resistivity. Taking into account these parameters through the joint interpretation of dielectric and electrical resistivity measurements significantly improves assessment of hydrocarbon saturation.
Going Beyond the Tally book: A Novel Method for Analysis, Prediction and Control of Directionally Drilled Wellbores using Mechanical Specific Energy
Authors: Noynaert S. , Gildin E. 
Published: October 2014

Abstract
The following paper covers work completed at Texas A&M University regarding an innovative method to quantify the rate of change in a wellbore trajectory using mechanical specific energy or MSE. The use of MSE to anticipate the rate of change is a fresh approach to wellbore trajectory prediction using surface drilling data and is shown in our work to be an accurate predictor of dog-leg severity.
The use of horizontal drilling has expanded at an almost exponential pace as it has been applied to unconventional reservoirs, and yet, the process is still done in a reactive fashion. This is to say that, many horizontal drilling decisions are still made by the directional driller using only his tally book with simple records showing the results of his prior actions. Using the correlation presented in this paper, a system has been developed which allows for accurate prediction of the rate of change of wellbore deviation while a drillstring is being rotated ahead.
Predictive models, typically centered on WOB or RPM, have been in existence for many years. However, one parameter whose effect on wellbore deviation has not been investigated is mechanical specific energy. MSE is a measure of the efficiency of the drilling process and has primarily been used for vibration analysis and rate of penetration optimization. Using published experimental data, a correlation was developed which shows a clear relationship between the dog-leg severity, rate of penetration (ROP) and MSE. The correlation requires only a few hundred feet of drilling before it is able to be tuned to match an individual well's results. With minimal tuning throughout the drilling of a well, good results can be obtained with regards to forecasting dog-leg severity as the wellbores were drilled ahead. The correlation was tested using data from multiple, geo-steered wells drilled in a shale reservoir. The analysis of the correlation using real-world data proved it to be a robust and accurate method of predicting the magnitude of dog-leg severity.
This work is a part of the overall industry push to understand the mechanics of what is occurring downhole and their effect on the many aspects of the drilling process. The correlation allows for the prediction of what is now becoming a vital part of many of the wells we drill: the wellbore's trajectory while rotating. It works particularly well in horizontal or near-horizontal portions of the well, which is where the wellpath trajectory matters the most with regards to overall well productivity. In addition, there are no special data requirements, only standard surface drilling parameter data. Overall, the use of this correlation results in a smoother wellbore, drilled with a faster overall ROP with a better chance of staying within the geologic targets.
Understanding Mechanisms for Liquid Dropout from Horizontal Shale Gas Condensate Wells
Authors: Altman Raphael , Fan Li , Sinha Shekhar , Stukan Mikhail , Viswanathan Anup 
Published: October 2014

Abstract
The presence of nanopores in tight, rich-gas-condensate wells (3,000 to ~10,000 scf/STB) may hold long-term gas/oil ratio (GOR) trends constant with time as observed in production data from some North American shales. This finding contrasts with some of the numerical simulation forecasts performed on calibrated pressure/volume/temperature (PVT) models based on bulk laboratory PVT data. Research efforts have pointed to a decrease in the PVT phase envelopes of hydrocarbon fluids confined in nanopores. This would delay the onset of dew point pressure and condensate liquid dropout and could be one of the causes of the observed constant producing GOR in the wells studied.
An understanding of fluid properties in nanopores is fundamental to predicting the onset of condensate dropout in shale reservoirs. One approach may be molecular dynamics simulations that can shed the light on the difference in behavior of larger-chain hydrocarbon molecules at kerogen surfaces and bulk pore space. Additionally, shale gas condensate production management may be more fully optimized by understanding both the effects of hydraulic fracture degradation with drawdown and liquid dropout in the production string. An integrated approach of this kind can help optimize liquid-rich shale reservoir production management.
Recovery Mechanism of Thermal Process in Naturally Fractured Tight Diatomite Heavy Oil Reservoir
Authors: Harness Paul , Tang Guo-qing , Inouye Art , Lowry Dustin 
Published: October 2014

Abstract
The Monterey siliceous diatomite resource is an unconventional resource which traps several billion barrels of heavy oil in San Joaquin Valley. Thermal processes, such as steam injection, have been successfully used to stimulate heavy oil production from diatomite reservoirs since the 1990's. Significant improvements in oil production have been achieved using the steam injection process however, the recovery mechanism remains unclear. This work is aimed at uncovering the recovery mechanism for steam injection in diatomite heavy oil reservoirs.
A comprehensive experimental study focused on the recovery mechanisms utilizing a specially designed high temperature and pressure core test system, integrated with high resolution CT-scan imaging technology with advanced test protocols to simulate reservoir conditions. Reservoir rocks with different lithologies (sandy, clean, and clayey), various viscous crude oils (API=14-22), and synthetic formation brines were used in this study. Imbibition core tests at elevated temperatures up to 400°F were conducted to study the recovery mechanism by the steam injection process.
Our study showed that oil recovery is dominated by hot water imbibition from fracture networks in the tight matrix where oil is stored. As the temperature is increased from reservoir temperature to steam temperature (400 °F), the oil recovery is symmetrically increased from less than 10% to around 60%. A proportional linear relation between oil recovery and temperature is observed which can be used to optimize field steam injection operations. Results indicate that thermal processes alter wettability toward increasing water-wetness. Wettability alteration experiments at elevated temperatures were also observed with a high resolution industrial CT-scanner.
New Approaches to Transferring Skills to the Next Generation
Authors: Lomas Adam. T. 
Published: October 2014

Abstract
Author's speak recently of a "disruptive shake-up" in the energy industry. The relationship between NOC's IOC's and service companies has changed beyond recognition, but one parameter has remained the same throughout these turbulent years – the need for talent to develop the increasingly complex oil and gas fields.
The constraint on being able to invest in mega projects, is often not the lack of capital or even the increasingly complex technology required to drill deeper, horizontal or in (sub) arctic conditions, it is the lack of talent to deliver them.
The oil industry has experienced a number of "boom and bust" cycles since the 1970's and each oil price crash has led to cuts to keep operating costs low. The first cuts almost always hit training and travel budgets and the 10$ oil in the early 90's led to a freeze on hiring new graduates into the industry and massive cuts in training and development.
A New Approach for Fast Evaluations of Large Portfolios of Oil and Gas Fields
Authors: Castiñeira David , Mondal Anirban , Matringe Sebastien 
Published: October 2014

Abstract
This paper presents a new systematic process for the evaluation of large portfolios of oil and gas fields where the performance and economic value of an entire portfolio is very rapidly derived. The automation of this workflow relies on some key technological developments, namely an automated algorithm for decline-curve analysis, and data mining studies of workovers and new well performance.
The automated decline-curve analysis tool presented here uses an event detection algorithm combined with quantile regression technique design to provide a robust probabilistic estimate of future PDP (proved-developed-producing) reserves on a well-by-well basis. Individual well behaviors are then aggregated stochastically to provide expected field and portfolio declines, with uncertainty ranges. Future well trends are estimated using probabilistic type-curves computed by data mining algorithms. Wells and fields are then individually assessed and ranked in terms of reserves and production metrics and financial information can be used to assess the value of the portfolio with a high-level of granularity.
A large portfolio of oil and gas fields in Texas and Louisiana is analyzed in this paper using the proposed methodology. For this portfolio computed decline rates, PDP reserves and cash flows are provided. Analysis of expected production from new wells and estimates of workover performance are also presented.
The analytical approach presented in this work is being used daily for comprehensive portfolio evaluations in the US and represents a significant change in the way divestitures and acquisitions evaluations are currently performed in the industry.
Mathematical Modeling of Production Decline For Conventional and Unconventional Reservoir
Authors: Mikolajczak Edyta 
Published: October 2014

Abstract
The determination of reservoir flow rate is the key issue during the planning phase of hydrocarbon production in conventional and unconventional reservoirs. Production change forecasts are presented with decline curve based on analytical or empirical dependencies. Curve matching depends on the appropriate mathematical model which was used.
The aim of this paper is the possibility to implement various mathematical models analysing production process for hydrocarbon wells. The idea of this paper is to use Logistic equation, which has widespread use in modeling the growth of the population, for modeling production decline and test results for the Arps model and the Logistic equation for predicting gas production for both conventional and unconventional resources.
This paper presents a study on the forecasting of gas well production. Part one focuses on the conventional reservoir, while part two presents predicting the production of unconventional gas wells. New mathematical formula has been proposed taking into account effect of gas desorption from organic matter of the shale.
Analytical models provide more reliable forecasting capability. The logistic curve was successfully applied to conventional and unconventional reservoirs. Once, it is useful to understand the dynamic behavior of the decline resulting from phenomena for unconventional reservoir. The modeling results were verified by the real industrial data.
Enzyme Penetration Tests on Carbonaceous Rocks for Application to Enhanced Oil Recovery
Authors: Haastrup Birgit 
Published: October 2014

Abstract
Many different Enhanced Oil Recovery (EOR) methods have been applied on reservoirs with declining oil production. Currently there is a demand for new and green technologies in order to increase oil recovery. One of the technologies in focus is Enzymatic EOR (EEOR).
One of the newest proposals for the application of enzymes utilizes their ability to alter the wettability of the reservoir rock. Both laboratory experiments and pilot plant tests have been carried out (although mainly for sandstone rocks) to study this effect. However little is known about the applicability of enzymes on carbonate reservoirs.
The aim of this paper is to outline the penetration behavior of two different enzymes on carbonate cores, in order to check whether the enzymes get irreversibly adsorbed in the rock and, thus, would "get lost" close to injection sites if injected for EOR. This is an important study in order to investigate the feasibility of EEOR application in the North Sea carbonate reservoirs.
Two enzymes, an esterase and a lipase, were selected based on their ability to change the wettability and adhesion properties and also desorption rates on cleaned cleaved chalk surfaces. The penetration tests were conducted on North Sea chalk reservoir cores.
The tests showed that the esterase does not penetrate chalk whereas the lipase does. When the core is previously unused a recovery rate of up to 35% of the lipase is achieved.
Experimental Study on Stress Sensitivity of Naturally Fractured Reservoirs
Authors: Tian Ye 
Published: October 2014

Abstract
Stress sensitivity of a naturally fractured reservoir is regarded as pronounced where pressure decrease induced by production is believed to cause significant changes in fracture apertures. Most laboratory investigations suggest that decrease in reservoir pressure would lead to great loss of fracture conductivity and rapid production decline. But till today, no such evidence from the production practices has been documented; on the contrary, there are some reported cases where depletion could potentially maintain even increase the extraction rate.
To solve the discrepancy, experiments were performed when permeability of fractured cores was measured in the process of increasing confining pressure with a constant pore pressure. In production, formation overburden pressure represented by laboratory confining pressure seldom alters and it is the pore pressure that virtually changes. To cope with that, effective stress was applied in the study, where Biot's coefficient for fracture effective stress was theoretically derived and found equal to fracture porosity. Improved evaluation method was then given based on effective stress and stress-dependent permeability correlations. At last, a general evaluation criterion was established where stress sensitivity levels were classified based on Stress-sensitivity Index.
The evaluation of four cores reveals that, the stress-dependence of fracture permeability turns out to be weak if evaluated with a low value of Biot's coefficient directly resulting from small fracture porosity. The study also indicates that fracture is strongly sensitive to confining pressure change in laboratory, but only weakly sensitive to the reservoir pressure change in production, which might reconcile the discrepancy between laboratory study and production practice.
Analysis of Reservoir Pressure Transients: A Wave Physics Approach
Authors: Vitus Ohazuruike Lotanna 
Published: October 2014

Abstract
This research work presents an investigation on a wave physics approach to pressure transient analysis. It is hinged on the view that a pressure transient phenomenon has an associated wave behaviour. A Reservoir pressure transient partial differential equation is developed by importing the pressure transient velocity into the general wave partial differential equation. The equation is then solved using the Boltzmann transformation. The resulting equation presents a mathematical definition of a reservoir pressure transient from a wave physics viewpoint. Spectral and Time Series plots of the model and field data predicted pressure transients are presented. Observation shows a similar trend in behaviour for both plots and discrepancies possibly due to reservoir heterogeneities, noise in data and the likelihood of a counterpressure effect from the restrictions.
Economic Analysis of Solar-Based Thermal Enhanced Oil Recovery
Authors: Anderson Timothy 
Published: October 2014

Abstract
One of the most promising technologies that has been developed to reduce the cost of thermal enhanced oil recovery (TEOR) is solar-based TEOR, where solar energy, instead of natural gas or other fossil fuels, is used to heat the steam or fluid used in TEOR. Previous studies have shown that solar-based TEOR is significantly more environmentally advantageous than traditional TEOR, but none has thoroughly analyzed the economic viability of solar-based TEOR. This study analyzes the cost effectiveness of solar-based TEOR in comparison with traditional TEOR setups in both the early-time (first ∼30 years of production) and late-time (after capital has been paid out) production stages. For the early-time, production data from the Kern River Oil Field was analyzed, as this field has a typical TEOR setup and complete record of steam injection and oil production data over its lifetime. The early-time analysis focused on the effect that optimization of the size of a steam generation setup has on the net present value (NPV) of various solar-based and traditional TEOR setups. The late-time analysis focused on deriving and analyzing a cost model for TEOR in the late-time. The cost model was based on calculating the total energy needed by the system (heating, lift, and maintenance), and then calculating the cost of this energy. The results of the analysis for the early-time and late-time was that a 100% solar setup is the most economical setup in both cases. In the early-time, the analysis showed that 100% solar TEOR consistently had the highest NPV for various scenarios of optimizing the production data. NPV for 100% solar was also the highest except at moderate (∼8%) interest rates. In the late-time, 100% solar was the least costly, as it had the lowest operations and maintenance costs, assuming that these costs were the same for all solar fractions. Further work would include a more rigorous analysis of the maintenance costs and efficiency degradation of TEOR systems in the late-time. This analysis can be carried out once industry data becomes available for maintenance costs and efficiency degradation. This study shows that solar-based TEOR is not only environmentally viable, but also offers substantial economic advantages. Overall, TEOR is a very promising technology that offers an opportunity to make petroleum extraction cleaner, more economical, and more effective.