bluuebunny/crossref_metadata_2025_split huggingface dataset:
New Horizons in Gas Hydrate Recovery using Fluorine and Microwave Technology
Authors: Garg Rachit , Ogra Konark , Choudhary Arpit , Menezes Richard 
Published: June 2014

Abstract
Methane gas hydrates are cages of water molecule that trap small, low molecular weight gas molecules e.g. methane, ethane, hydrogen sulfide etc. the enormous quantity of gas stored in them (1m3 G.H = 180m3) makes them an important area of research for the scientist and petroleum engineers.
Over the years the various theoretical techniques for recovery of the gas hydrates are 1.thermal injection 2.inhibitors 3.depressurization. However due to inefficient and economic unfeasibility it is difficult to recover the methane from gas hydrates.
Low injectivity reservoir, small thickness of G.H bearing zone, heat loss especially in permafrost region, also the cost of the inhibitors (which change the thermodynamic condition) is litre of methanol makes it uneconomical, finally depressurization of an adjacent free gas zone can effectively dissociate hydrate but the endothermic nature of the hydrate decomposition will decrease the reservoir temperature and which may temporarily decrease the flow rate.
The technical problems with estimating the gas hydrate are
Technology to safely and economically produce methane from G.H deposits. Safety and drill floor stability related issues related to drilling through G.H bearing accumulations.
This paper deals with a new technique of a In this technique, the pressure of the fluids in contact with hydrate is lowered, pushing the hydrate out of its stability region and leading to its decomposition. Because no extra heat is introduced into the reservoir, the heat of decomposition must be supplied from the surrounding formation.
recovery of methane from G.H. This technique involves use of a micro strip antenna which has huge power gain and is relatively inexpensive, with wire line the tool is placed in well bore and frequency of 2450 MHz is released which melt the G.H into water and methyl radical (as they are almost similar to ice) such that they disturb the thermodynamic condition, then the fluorine is injected, this results in reaction between methyl radical and injected fluorine (halogenation), which is strongly exothermic (-431KJ/mole), this reaction propagates the reaction and simultaneously we have solubility of methyl fluoride with water which is 166cc/ 100 ml of water. This pressurized gas solution is then recovered via tubing from production well. Later by applying wurtz reaction, electrolysis and cracking methane can be recovered.
The main advantage of using this technique is micro waves interact strongly with some materials and weakly with others, energy absorption depends on microwave frequency, sample composition, temperature. The chemical compound fluorine is abundant in nature (540000ppb) and methyl fluoride is environmental friendly.
A New Flow Skin Factor Formulation for Hydraulically Fractured Wells in Gas Condensate Reservoirs
Authors: Mahdiyar H. , Jamiolahmadi M. , Sohrabi M. 
Published: June 2014

Abstract
Fracturing is one of the most common well stimulation techniques especially for tight gas-condensate reservoirs. Gas condensate flow around hydraulically fractured wells (HFWs) is different from conventional gas oil systems. This is mainly due to phase change, condensate drop out and coupling (i.e., the increase of relative permeability as velocity increases and/or interfacial tension decreases) and inertial (i.e., the reduction of relative permeability as velocity increases) effects.
Description of HFWs in gas condensate reservoirs using the existing reservoir simulators requires the use of very fine grids to capture the significant changes of flow and rock properties occurring in and around the fracture. This tasks it very cumbersome, time consuming and impractical.
In this work a two dimensional mathematical simulator has been developed, which is based on finite-difference methods and accounts for the combined effects of coupling and inertia using our recently developed generalized correlation. This single-well model, which simulates the steady-state flow of gas and condensate around HFWs, also allows for phase change in these low interfacial tension systems. A series of sensitivity studies were carried out using this simulator. The results were used to develop a general method for estimation of flow skin factor based on the definition of dimensionless effective fracture conductivity. In the proposed method the skin factor expressing the impact of pertinent parameters are then converted to an effective well bore radius, which can be used by a reservoir engineer to conduct a realistic open-hole simulation of flow around HFWs.
Low IFT Gas-Oil Gravity Drainage in Fractured Carbonate Porous Media
Authors: Karimaie H. , Torsæter O. 
Published: June 2014

Abstract
This paper addresses a study of gas-oil gravity drainage in fractured carbonate rock subjected to gas injection in low interfacial tension. The purpose of the experiments described in the paper was to investigate gas injection in fractured carbonate reservoirs in both secondary and tertiary cases (after water injection), focusing on gravity drainage using equilibrium gas followed by re-pressurization. Gas injection experiments were performed on 20 cm long and low permeable outcrop chalk core surrounded with a fracture established with a novel experimental set-up in reservoir conditions. The core was saturated with binary mixture live oil consisting of C1 and C7 of a known composition, while the fracture was filled with sealing material to obtain a homogeneous saturation. After core initialization, the sealing material was removed by increasing the temperature to higher than its melting point and displaced by live oil. Gas was then injected into the fracture and gravity drainage experiments were performed in low interfacial tension (&lt; 0.5 mN/m) where the IFT between the phases were measured experimentally by selecting the proper pressure and temperature.
Experiments were performed at different pressures and reversibility of the effect of the interfacial tension was checked by re-pressurization process. The oil recovered from the bottom side of the block was measured versus time.
Based on the results of this study, the recovery of oil showed a significant increase by re-pressurization in gravity drainage process. It was also clear that low-IFT gravity drainage is capable to recover a significant amount of oil in fractured reservoirs even after water injection.
Bidding Schemes and Their Impacts on Risk Assessments by Oil Companies
Authors: Rodriguez M. R. , Suslick S. B. 
Published: June 2014

Abstract
Petroleum auctions in US-GOM and Brazil are a common value first-price sealed bid, with fundamental differences on bidding systems defined by the regulators regarding the winner proposal. The US-GOM bidding model for offshore exploration areas considers the higher bonuses values as the winner offer. In Brazil, two main variables define the winner: the signature bonus and the minimum exploration program (PEM). The PEM aggregates value to the government, as it is a firm commitment to acquire geological data on the first exploration years. The amount of PEM committed reflects the importance of the exploration area for the bidders. This information not necessarily could be addressed by the simple high bids' analyses as in the US-GOM system. The Brazilian bidding model allows the bidders to a "full risk assessment" on their competitor's bidding behavior. This paper compares the risk perceptions of oil companies using the US-GOM and Brazilian bidding results for years 2005 and 2006, assuming the same oil price scenario and areas of similar geological settings. Another contribution of this paper is to present a competition model for evaluate different risk perceptions by using measures such as cash bonus (upfront money) and PEM (a long-term disbursement) generated by diverse bidding schemes. Preliminary results show that Brazilian high bids are in the same range of US-GOM bonuses (20,000.00 to 30,000.00 US$/km2). Nevertheless, considering bonus and PEM as the winner offer, Brazilian high bids double the American ones. The competition model used for evaluate the firm performance in both bidding systems indicates that the utilization of bonus and PEM allow companies' decision makers to perform a better portfolio management, but demands the inclusion of a solid risk perception to select the best areas for bidding.
Vorticity-Based PEBI Grids for Improved Upscaling of Two Phase Flow
Authors: Evazi M. , Mahani H. , Hejranfar K. , Masihi M. 
Published: June 2014

Abstract
Highly detailed geological models, which are primary inputs to reservoir simulator, necessitate the reduction of number of grid blocks to be used in the solution of flow equations. However preparing a coarse scale model that can mimic the fine scale behavior is a challenging task. Cartesian grid suffers from some shortcomings, as in adaptation with geological and geometrical features and the phenomenon of grid orientation effect that motivates the use of unstructured grid. Different methods have been used for this purpose, but no one is robust enough that justifies the need for more research.
In this paper, we propose an unstructured grid generation scheme that utilizes the vorticity of fluid flow in porous media as the determining parameter for background grid generation. It entails the simulation of single-phase flow on the fine grid and obtaining the velocity field and subsequently vorticity map. Vorticity is then used to generate the background grid that plays an essential role in the generation of desired final coarse grid. At this stage user needs to determine the value of some parameters such as maximum and minimum spacing, vorticity cut-off and intensity degree. Advancing front method and Delaunay triangulation are then resorted to provide the triangular and Voronoi (PEBI) grid. The developed technique, which aims at capturing both flow and geologic details, produces grids with higher resolution at critical vorticity areas, such as around layer boundaries, and with lower resolution where vorticity is negligible, like in homogenous regions.
This technique is applied to two channelized and heterogeneous models and the results are presented. Two-phase flow simulations are performed on the generated coarse grids and the results are compared with the ones of fine scale grid and uniformly generated coarse grids. The results show a greater accuracy compared to uniformly gridded models.
Innovative Implementation of Compositional Delumping in Integrated Asset Modelling
Authors: Vignati E. , Cominelli A. , Rossi R. , Roscini P. 
Published: June 2014

Abstract
In reservoir simulations it is a common practice to use a limited number of components to describe the reservoir fluids, ranging from 2 (black-oil models) to 5-12 (compositional equation of state based models). On the opposite, surface models usually require a greater number of components, typically from 15 to 30. The hydrocarbon components used in the surface model are usually lumped into pseudo-components in the reservoir. This disparity in the description of the mixture may become an issue whenever integrated asset models are developed with the aim of linking surface process and reservoir engineering.
Leibovici et al.[10] presented a method to delump pseudo-components and predict the detailed phase compositions according to the results of a flash calculation performed on a lumped mixture. Leibovici et al.[11] proposed to use the delumping in the context of compositional reservoir simulation to predict the detailed composition of the produced fluid. The key-feature of this method is to calculate the phase equilibria with a simplified fluid and transfer the results in the detailed fluid model description applying a linearization in the space of equation of state parameters. They implemented this method by post-processing the results of a compositional simulation and use computed phase velocities to trace the delumped components. The delumping method was then implemented in a commercial compositional reservoir simulator by coupling the algorithm with a tracer advection module. The simulator option is usually referred as compositional tracer option. In this paper we used the Leibovici et al. approach in the context of the integrated asset modeling of complex reservoir fluids. Process models with detailed compositional formulation were linked to compositionally simpler reservoir models, using the compositional tracer option to feed the surface model with the produced reservoir streams.
The proposed workflow was applied to simulate two different recovery processes, namely a) a gas injection below the dew-point in a sour gas condensate reservoir; and b) a miscible gas injection in a near critical volatile oil reservoir. Results of this implementation, in which detailed components are traced in the reservoirs, are compared to integrated simulations where all the stages, including reservoirs, are modelled using detailed composition.
Non-Darcy Flow: Laboratory Measurements in Unconsolidated Porous Media
Authors: Macini P. , Mesini E. , Viola R. 
Published: June 2014

Abstract
In recent years, the petroleum industry has shown a renovated interest in Non-Darcy flow, in order to better understand reservoir performances. Non-Darcy flow is typically observed in gas wells when the fluids converging to the wellbore attains the velocity peculiar of turbulent flow. As a consequence, pressure drop around the wellbore cannot be estimated from the classic Darcy equation, where the pressure gradient is a linear function of the flow velocity. In that case, in fact, the use of Darcy equation would lead to inaccurate production performances evaluation.
In order to describe correctly this phenomenon, the well-known Forchheimer equation is normally used, where the inertial coefficient ß is defined. In gas wells this coefficient is usually determined by the analysis of multi-rate pressure tests performed on site. Unfortunately, such data are not easily available (or not economical) in many cases. So, it is a common practice to use particular theoretical and empirical correlations that can be derived by exploiting experimental values of the inertial coefficient.
This paper reports a laboratory study in which the inertial coefficient ß can be correlated to the structure of the porous media, and, in particular, of its grain size distribution. Gas flow laboratory experiments have been performed on laboratory models of glass beads and natural sands of different sizes. Moreover, porosity and permeability, together with the Klinkenberg constant, have been determined on natural sand cores with both flat and peaked grain size distribution, and a correlation with the Forchheimer equation has been checked. Forchheimer's number has been calculated and correlated to the superficial velocity as well. In the light of the above, specific laboratory equipment has been devised in order to rely on a wide range of flow rate under appropriate pressure gradients.
Improved And Robust Drilling Simulators Using Past Real-Time Measurements And Artificial Intelligence
Authors: Nybø Roar , Bjørkevoll Knut S. , Rommetveit Rolv , Skalle Pål , Herbert Mike 
Published: June 2014

Abstract
Time series data from past drilling operations are an under-utilized resource in oil-companies. In this paper, we present a simple example of how knowledge implicit in time series can be complementary to traditional modeling. In particular our system reduces the occurrence of a false kick alarm typically seen when making a connection during drilling.
Monetizing Gas: Focusing on Developments in Gas Hydrate as a Mode of Transportation
Authors: Rajnauth Jerome , Barrufet Maria 
Published: June 2014

Abstract
Natural gas and energy resource management is a major challenge in the rapidly changing global and business environment. Increase in gas recoveries and gas production have led a major review in the ways of transporting natural gas energy. Monetizing gas has now become a high priority issue for many countries. Natural gas is a much cleaner fuel than oil and coal especially for electricity generation.
Interest in gas hydrate being used as a means of transporting natural gas has increased over the last decade. New technology development has been focusing on using gas hydrates as a way of converting gas to solids to transport to markets around the world. Gas hydrate may be a viable means of storing and transporting gas but more focus should be given to some critical considerations for this gas hydrate development.
This paper would discuss some of these issues as we move towards monetizing gas in the form of hydrate. These include present and future gas prices, energy balance in hydrate formation and re-gasification, storage of the hydrate, form of transporting the hydrate and distances to be transported. Other important factors are re-gasification technologies, economics compared to other gas transportation modes, environmental, climate and other issues.
The Impact of Sandstone Strength's Behavior as a Result of Temperature Changes in Water Injectors
Authors: Tovar J. , Navarro W. 
Published: June 2014

Abstract
In water injection programs it is accepted that the temperature at which water arrives at the formation will cause the rock to shrink resulting in a reduction in the minimum horizontal stress and possibly a fracture of the rock. This effect is known as TIF or Thermally Induced Fracturing. However, little research has been carried out as to how the cooling of the rock by the injection water affect the formation mechanical properties. This paper presents work carried out to determine the effect of temperature changes on the strength of sandstone reservoirs used for water injection.
An effort was initiated by Pluspetrol Norte, S.A. as part of their produced water disposal programs to develop an understanding as to how various sandstone reservoirs used for re-injection respond to temperature changes and what implications can it have for their operations. Pluspetrol production comes from two(2) main blocks in Northern Peru, Total water production has reached over 1000000 bwpd of which over 450000 bwpd are currently being re-injected throughout both blocks.
A large core testing program was designed and completed to measure unconfined rock strength in a number of sandstone cores available from both blocks. The cores were heated and cooled and their strength measured to identify possible changes in strength magnitude. The results obtained were analysed and compared with those available in a large geomechanical model of the blocks developed earlier known as the Custodian(1), a new predictive model was developed using the results obtained. A number of simulations were carried out using a TIF model to compare the measured field data during water re-injection with the predictions from the TIF model using the new strength model. These results are presented in detail and its application to other geomechanical problems such as sand production in water injectors is also discussed.
Petro-Elastic Models: How Many and at What Scale?
Authors: Alfred D. , Atan S. , Hamman J. G. , Caldwell D. H. 
Published: June 2014

Abstract
This paper describes an integrated workflow that determines the minimum number of petro elastic models required to adequately predict elastic properties for a given flow scale. The workflow involves the formulation of scale-dependent petro-elastic models (PEM) and petro-elastic facies from well logs. Then through an error evaluation technique, determines the minimum number of PEMs required and the maximum vertical grid size limit for the flow scale. The validity of the fine scale PEMs across different scales is also tested in the workflow.
Elastic properties of reservoir rocks can be predicted through petro-elastic models which relate fluid and intrinsic reservoir properties to elastic properties through mathematical functions or rock physics models. Although we would like to generate PEMs at flow scale, very often the PEMs are generated from logs that are consistent with core data. A PEM is lithology and rock fabric specific. In an upscaled flow model, the lithologies or textures are mixed. Fine scale PEMs may no longer adequately describe the elastic properties of the reservoir at flow and seismic scale.
Prediction is improved in a flow model that integrates all available measurements. Scale inconsistencies of the measurements need to be addressed for better integration and prediction. In this paper we will show that through a unique and iterative approach, PEMs must be generated at flow scale for improved integration. The methodology has been tested with synthetic data and resulted in a better predictive flow scale model, which is consistent across all scale resolutions.
Continuous History Matching a HPHT Gas Condensate Field during the First Two Years of Production
Authors: Christoffersen K. R. , Quin J. G. , Zweigel P. , Hansen O. R. , Zaostrovski A. 
Published: June 2014

Abstract
The HPHT Kristin field is located offshore Norway in 350 m water depth and is developed with four sub-sea templates. Since production began in November 2005, reservoir pressure has dropped around 4 times faster than predicted. The main Kristin field statistics include: an initial pressure of 910 bar, a reservoir temperature of 170°C, a dew point of around 400 bars (rich fluid accounts for 50% of income) and in-place volumes of around 100 GSm3 of gas and 100 MSm3 of condensate. The Kristin reservoir section comprises three separate Jurassic sandstone units and the field is segmented by faults. This paper describes the process of continuously history matching pressure decline during the first two years of production in Kristin using: production data, RFT pressures from wells drilled following production start-up, shut-in wellhead pressures, and data from two bottom-hole gauges. Close multidisciplinary cooperation between geophysicists, geologists and reservoir engineers has been key to ‘re-understanding' the Kristin reservoirs since production start-up and has facilitated the process of tuning the simulation model to obtain a better history matched model. The most important modifications have been the introduction of horizontal pressure barriers to match RFT pressures, and a significant reduction of pressure support from the eastern part of the field. The poor pressure support is interpreted to result from enhanced fault seal in one of the main reservoir units, and a rapid easterly decrease in reservoir properties in the other (main) reservoir unit. These changes have been directly input into the simulation model and have resulted in a good match of the pressure history from the 11 producing wells. Directly input into the simulation model has shortened the updating cycle to a few minutes and saved several months in the history matching process. Work is currently ongoing to refine a more detailed geological model based on these results, and the additional knowledge gained by testing different solutions directly in the simulation model. This improved understanding of the reservoir behaviour also gives valuable input to the uncertainty study required before updating official reserves.