bluuebunny/crossref_metadata_2025_split huggingface dataset:
NMR Response of Brine, Oil, and Methane in Organic Rich Shales
Authors: Tinni A. , Odusina E. , Sulucarnain I. , Sondergeld C. , Rai C. 
Published: June 2014

Abstract
The application of NMR methods to evaluate the fluid content in hydrocarbon reservoirs requires the understanding of the NMR response of the fluids present in the rock. The presence of multiple fluids which can be in liquid, gaseous or adsorbed phase in nanometer size pores (associated with various minerals and organic matter) add another degree of complexity to the interpretation of NMR data in shales. This report presents the findings of a laboratory study on the NMR responses of brine, oil and methane in shales. The acquisition of the NMR data was made at 2MHz.
NMR T2 distributions were acquired at TE = 0.2ms on companion core plugs from the Haynesville shale and at TE = 0.3ms for Barnett and Woodford shale samples. The NMR T2 distributions acquisitions were conducted on samples saturated with brine (2.5% KCl) and oil (dodecane). The NMR T2 data acquired on the native state samples (as received) showed a bimodal distribution with the dominant peak at T2 less or equal to 1ms. After saturation in parallel with oil and brine with increasing saturation pressures we observed in the case of brine an increase in amplitude of the NMR peak located at T2 less or equal to 1ms. At higher saturation pressures we observed a shift in the T2 time of this peak toward longer T2 times. When the samples were saturated with oil and the saturation pressure increased we observed the development of second NMR T2 peaks around 6-20 ms with no substantial increase of the peaks at T2 less than 1ms; the observed distributions are bimodal.
The measurements with methane were conducted at TE = 0.3ms on 2 Haynesville core plugs at a methane pressure of 4000 psi and a confining pressure of 5000psi. The NMR T2 distributions that were essentially unimodal in the as received state with a peak at 0.35-0.4ms, evolved into a bimodal distribution in response to the injection of methane. The first peak was observed at the same T2 time as in the as received state with no substantial change in amplitude and second peak was located at 10-20ms ms.
This results show that the NMR response of methane and oil is similar. Monitoring the saturations increase with NMR show that brine can enter the entire pores spectrum while oil and methane have access only to a fraction of the pore space.
Assessment of the Mexican Eagle Ford Shale Oil and Gas Resources
Authors: Morales Velasco C. A. , McVay D. A. , Lee J. 
Published: June 2014

Abstract
The Eagle Ford shale is the shale with the greatest expectations in Mexico, given its abundant hydrocarbon liquids production and success in the US. Resource estimates were first published by the EIA and PEMEX in 2011, and new production and geologic information has been obtained in the area since then. The objective of this paper is to provide an important updated assessment of oil and gas reserves, as well as contingent and prospective resources, in the Mexican Eagle Ford shale and to quantify the related uncertainties.
Given the considerable uncertainties in shale reservoirs, a probabilistic decline-curve approach was chosen, as it allows performing a play-wide assessment with available production data, and it quantifies the uncertainty in the resource size. Analog areas in the US Eagle Ford shale were defined based on available geologic information in both the US and Mexico. The Duong model coupled with a Markov Chain Monte Carlo (MCMC) methodology was used to analyze and forecast production of wells located in the defined analog sectors in the US Eagle Ford shale. By combining the results of individual-well analyses, a type curve and estimated ultimate recovery (EUR) distribution was obtained for each of the defined analog sectors. These distributions were combined with well-spacing assumptions and sector areas to generate the prospective-resources estimates. Similar methodology was used to estimate the reserves and contingent resources associated with the few existing wells.
As of March 2013, the total prospective resources (P90-P50-P10) for the Eagle Ford shale in Mexico are estimated to be 527-1,139-7,268 MMSTB of oil and 17-37-217 TSCF of gas. Estimated reserves associated with existing wells and corresponding offset well locations are 18-35-60 BSCF for gas and zero for oil. Estimated contingent resources are 14-64-228 MSTB of oil and 8.5-13-26 BSCF of gas. For comparison, total resources (including reserves) for the US side are estimated to be 2,950-8,250-23,530 MMSTB and 34-91-266 TSCF, as reported by Gong et al. (2013). The results of the work presented here should provide a more reliable assessment of the resource size and uncertainty in the Mexican Eagle Ford shale for use in resource exploitation planning.
The Potential Effect of Network Complexity on Recovery of Injected Fluid Following Hydraulic Fracturing
Authors: McClure Mark 
Published: June 2014

Abstract
A numerical modeling study was performed to investigate fluid recovery following hydraulic stimulation in low matrix permeability formations. A simulator was used, CFRAC, that implicitly couples fluid flow with the stresses induced by fracture deformation in two-dimensional discrete fracture networks. An unstructured mesh was created around the fractures to simulate leakoff and flow in the matrix. Four simulations were performed in which fluid was injected, the wells were shut in, and then fluid was produced back to the surface. The baseline simulation contained a single, linear fracture propagating away from the wellbore. The other three simulations used a stochastically generated network of natural fractures and assumed that as hydraulic fractures propagated through the formation, they terminated when they intersected natural fractures. The termination process created complex, branching fracture networks. The simulations showed that fracture network complexity reduced fluid recovery because the natural fractures, which were not perpendicular to the minimum principal stress, closed at an elevated fluid pressure and created barriers for flow between the wellbore and the open, fluid-filled fractures away from the well. However, if the transmissivity of closed fractures was too low, the fracture network was inhibited from becoming complex, and fluid trapping was not as severe. In the two complex fracture network simulations with lower closed fracture transmissivity, the shut-in pressure transient showed abrupt changes in slope, which were caused by episodic growth of the fracture network due to leakoff of fluid into natural fractures, rapid propagation of opening along the natural fractures, and subsequent initiation of new hydrualic fractures. In practical applications, the observation of abrupt changes in slope during shut-in could be taken as evidence that episodic fracture propagation is occurring, which would imply a complex and branching fracture network. In one of the three complex fracture network simulations, it was assumed that closed fractures had relatively high transmissivity, and abrupt changes in the slope of the shut-in transient were not present, even though a complex fracture network developed during stimulation.
Cross-Correlating Seismic Attributes With Cumulative Production from Horizontal Wells in the Middle Bakken Unconventional Reservoir
Authors: Humphrey Robert , Su Chaohui , Murray Ian , Courtier James 
Published: June 2014

Abstract
The Middle Bakken reservoir is considered an unconventional play because the reservoir is relatively thin and tight. The reservoir also depends on hydraulic fracturing in laterally drilled wells to free commercial quantities of oil. The available 3-D seismic in the study area shows the reservoir to be seismically thin (i.e. below seismic resolution at the frequencies recorded). Additionally, the complex fracture network created by hydraulic fracturing contributing to the oil production cannot be measured by the existing 3-D seismic data that was acquired before the drilling and hydraulic fracturing took place.
Analysis in one 3-D seismic survey in the North Dakota Middle Bakken play recognized 16 seismic attributes from 99 extracted that showed some degree of correlation with cumulative productions from 19 Middle Bakken H1 lateral wells within the seismic survey area. After statistical variable selection methods were employed, only one seismic attribute (relative acoustic impedance) was found to have statistical significance to productivity. Identical analyses were employed using available geologic attributes to correlate to IP90, as well as correlating IP90 to a combination of seismic and geologic attributes.
This paper presents a seismic attribute based statistical methodology that has been used for productivity analysis, without the necessity of precisely knowing the mechanism, in the Hawkeye / Blue Buttes field area in the Middle Bakken reservoir in North Dakota. Examples of productivity analyses will be shown using seismic attributes and seismic attributes plus regional geology attributes.
Impact of Surfactants for Wettability Alteration in Stimulation Fluids and the Potential for Surfactant EOR in Unconventional Liquid Reservoirs
Authors: Alvarez Johannes O. , Neog Anirban , Jais Afif , Schechter David S. 
Published: June 2014

Abstract
Wettability alteration in shale formations can be an important factor in improving the performance of hydraulic fracturing treatments. The use of surfactants in the frac fluid, at proper concentrations, has shown to change wettability in Unconventional Liquid Reservoirs (ULR) favoring the process of imbibition. This study evaluates and compares the efficiency of anionic and nonionic surfactants in recovering hydrocarbons in carbonate and siliceous preserved side-wall core. The techniques developed also open the door for investigation of low concentration surfactants for enhanced oil recovery (EOR) in ULR.
Contact angle (CA) experiments were performed, using the captive bubble method, to measure the magnitude of wettability alteration on intermediate to oil-wet ULR core at reservoir temperature (165 °F). Different types of anionic and nonionic surfactants at field concentrations were used. The results showed that all surfactants lower the CA at the concentration tested. However, anionic surfactants showed better results as observed by lower contact angles. IFT measurements were also performed, using the pendant drop and spinning drop methods, at reservoir temperature using reservoir crude oil and anionic and nonionic surfactants at the same concentrations. The IFT reduction was similar for each type of surfactant compared to regular frac fluid without any surfactant, but anionic surfactant showed slightly better capability of reducing IFT than nonionic surfactants.
Computed tomography (CT) scan methods were used to gauge the performance of these surfactants in improving oil recovery. The magnitude of penetration or imbibition into artificially-fractured ULR cores was studied for both anionic and nonionic surfactants. Frac fluids containing surfactants were mixed with a dopant salt to trace the movement of these fluids and measure the penetration numerically. Both, anionic and nonionic, surfactants have higher penetration magnitudes compared to slick water without surfactant. However, anionic surfactants displaced a higher observable amount of liquid hydrocarbon from the shale cores. This observation agrees qualitatively with the results observed in the CA experiments where anionic surfactants showed the lowest contact angles. From the results obtained, it can be concluded that anionic surfactants alter wettability in these ULR core, giving lower CA, better spontaneous imbibition and higher oil recovery than nonionic surfactants. These observed wettability changes induced by surfactants mixed in the frac fluids can improve matrix penetration with spontaneous imbibition which opens further discussions for EOR potential in shale formations.
A Sensitivity Study of Potential CO2 Injection for Enhanced Gas Recovery in Barnett Shale Reservoirs
Authors: Yu Wei , Al-Shalabi Emad W. , Sepehrnoori Kamy 
Published: June 2014

Abstract
Shale gas production has been gaining worldwide attention over the past several years. This is due to the economic gas reserves using two current advanced technologies that are horizontal drilling and multistage hydraulic fracturing. Shale has a high total organic content (TOC) that may adsorb significant amount of natural gas. In addition, laboratory and theoretical calculations indicate that organic-rich shales adsorb CO2 preferentially over CH4. Hence, the extent of organic matter in shale plays an important role in determining the feasibility of CO2 injection with potential benefit of enhanced gas recovery (EGR).
The performance of CO2 injection and CH4 recovery in shale reservoirs is a complex function of several engineering parameters including fracture half-length, fracture conductivity, and fracture height, operating parameters such as injection volume and injection time, and geologic parameters including reservoir permeability, porosity, and thickness. Nevertheless, the effects of the above uncertain parameters on the process of CO2-EGR are not clearly understood and systematically studied. Therefore, it is absolutely critical to quantify uncertainties and investigate the most important influential parameters controlling this process.
In this paper, we employ numerical reservoir simulation techniques to model multiple hydraulic fractures and multi-component Langmuir isotherms. Two scenarios for CO2 injection are investigated when the primary gas production decreases to the economic limit: (1) CO2 flooding in two horizontal wells, and (2) CO2 huff-n-puff in a horizontal well. A series of reservoir simulations based on Design of Experiment (DOE) are performed on the best scenario to investigate the critical parameters that control this CO2-EGR process in the Barnett Shale. This work enables operators to plan ahead of time and optimize a tertiary shale gas production process by considering the different investigated influential parameters.
A Study of Decline Curve Analysis in the Elm Coulee Field
Authors: Harris Seth , Lee W. John 
Published: June 2014

Abstract
In the last few years, the oil industry has turned its focus from shale gas exploration to shale oil/tight oil. Some of the important plays under development include the Bakken, Eagle Ford, and Niobrara. New decline curve methods have been developed as possible alternatives to the traditional Arps model for use in shale gas wells, but much less study has been done to verify the accuracy of these methods in shale oil wells. There is a great amount of uncertainty about how to calculate reserves in shale reservoirs with long multi-fractured horizontals, since most of these wells of have not yet been produced to abandonment. Although the Arps model can reliably describe conventional reservoir production decline, it is still uncertain which empirical decline curve method best describes a shale oil well to get a rapid assessment of expected recovery.
The models on which we concentrated were Arps with a 5% minimum decline rate, the stretched exponential model (SEPD), and the Duong model.
Our focus began in the oil window of the Eagle Ford, but we ultimately chose to study the Elm Coulee field (Bakken formation) instead to see what lessons an older tight oil play could lend to newer plays such as the Eagle Ford. Contrary to the assumption that these wells were still in linear flow, we found evidence from diagnostic plots that many horizontal wells in the Elm Coulee that began producing in 2006 and 2007 have entered boundary-dominated flow. In order to accommodate boundary flow we modified the Duong and SEPD methods such that once boundary-dominated flow begins the decline is described by an Arps curve with a b-value of 0.3.
We found from hindcasting that using early production history, up to the first six months, is generally detrimental to accurate forecasting in the Elm Coulee. This was particularly true for the Arps with 5% minimum decline or the Duong method. Early production history often contains apparent bilinear flow or no discernible trend. There are many possible reasons for this, such as the rapid decrease in bottomhole pressure and production of fracture fluid.
An Investigation of Gas-Condensate Flow in Liquid-Rich Shales
Authors: Al Ismail Maytham I. , Horne Roland N. 
Published: June 2014

Abstract
Production from the gas-condensate window of the liquid-rich shale plays in the US such as Barnett, Marcellus and Eagle Ford, has increased during the past few years. However, there is still a lack of understanding of the flow behavior of gas-condensate in liquid-rich shales when the flowing bottom-hole pressure falls below the dew-point pressure. Condensate dropout below the dew-point pressure leads to variation in the composition of vapor and liquid hydrocarbons. The phase behavior prediction is further complicated by the nanometer-sized pores of the shale formations where fluid-rock interaction could be different than in conventional reservoirs.
This work investigated the compositional variation of gas-condensate during flow through Marcellus shale in laboratory coreflooding experiments. During the experiments, a gas-condensate mixture was injected into the core and during the flow, gas samples were collected through ports spaced along the core holder. Then, the gas samples were characterized using gas chromatography for compositional analysis. The results were compared to equivalent experiments in Berea sandstone.
The gas-condensate sample used in the coreflooding experiment was collected from the Marcellus liquid-rich region and the experiments were conducted at reservoir pressure and temperature. Prior to conducting the experiments, the permeability of the Marcellus shale core and the Berea sandstone core were characterized using the pressure pulse decay technique and the Darcy flow technique; respectively.
Results from this study showed that the gas composition varies along the direction of flow during depletion. The change in gas composition is due to the combination of condensate dropout and relative permeability effects. However, the magnitude of variation in the gas composition across the Marcellus shale core was less than that in the Berea sandstone core. This is an indication that the amount of condensate dropout varies between shale and sandstone for the same fluid system and at similar flowing conditions. Hence, the phase behavior is affected by the additional fluid-rock interaction expected for the shale due to flow through nanometer-sized pores.
Compositional Streamline Simulation of CO2 Injection Accounting for Gravity and Capillary Effects Using Orthogonal Projection
Authors: Tanaka Shusei , Datta-Gupta Akhil , King Michael J. 
Published: June 2014

Abstract
The effective use of streamline simulators for flow simulation of high resolution 3D models relies on the ability to take large simulation time-steps with few pressure solutions. For processes that are convective, the streamline approach works quite well, but for flow simulation with strong capillarity or gravity terms, the maximum time step size is reduced, limiting the utility of streamline simulation. This is the case with the conventional operator-splitting approach, where the nonlinear terms associated with capillarity and gravity limit the time step size. The impact is particularly pronounced for compositional simulations that require numerous flash calculations.
This paper presents the development of a 3D 3-phase compositional streamline simulator and its application to field-scale CO2 injection. The novel aspect of our approach is the ability to incorporate gravity and capillary effects into compositional streamline simulation without adversely impacting its computational efficiency. In our approach, we use an orthogonal projection method to reformulate the streamline transport equations so that the fluxes of capillary and gravity are separated into components parallel and orthogonal to the total velocity defining the streamline trajectories. Fluxes parallel to total velocity are included within the solution of the convective flow equations on streamlines. The remaining terms are calculated on the underlying three dimensional grid. Our proposed formulation still uses an operator splitting approach, but the size of the remaining transverse flux correction terms is significantly reduced, allowing for large time steps.
The ability to effectively incorporate transverse fluxes in streamline transport calculations will be a step change in streamline simulation in general. We demonstrate that our proposed treatment of transverse fluxes allows us to efficiently study high resolution migration of CO2 in the subsurface with potential applications to both improved oil recovery as well as carbon sequestration. First, we establish the validity and computational efficiency of our approach using a series of numerical experiments and compare the results with a commercial finite difference simulator. Next, we apply the method to a field-scale CO2 WAG injection. The streamline model is shown to be particularly effective to examine and visualize the interactions between natural heterogeneity, capillary and buoyancy forces, and CO2 transport and the resulting impact on the vertical and areal sweep efficiencies.
Mechanism of Fluid Displacement in Sands
Authors: Buckley S.E. , Leverett M.C. 
Published: June 2014

The production of oil is accomplished as a result of its displacement fromthe reservoir by either gas or water, and the amount of oil recovery is limitedby the extent to which the displacing gas or water accumulates. This paperdescribes the mechanism by which the displacement is effected and theadvantages of water over gas as a displacing agent. In the light of the resultsof experimental observations of the flow of mixtures of oil and/or gas and/orwater through sands, certain conclusions are drawn relative to the changingcharacter of the displacement as depletion proceeds, and on the effects of theproperties of the fluids and of producing conditions on the ultimate oilrecovery.

Introduction
Crude oil has no inherent ability to expel itself from the pores of thereservoir rocks in which it is found; rather, it must be forcibly ejected ordisplaced by the accumulation of other fluids. Accordingly, a knowledge of themechanism by which one fluid is displaced by another is essential to anunderstanding of the fundamental process by which oil is recovered.
The displacing fluids normally available are gas and water, either or bothof which may exist originally associated with the oil in a potentially usableform or may be supplied to the reservoir from external sources. Gas is presentin most oil reservoirs. If the quantity is relatively small, it may existoriginally completely dissolved in the oil, but if the quantity exceeds thatwhich may be held in solution by the oil at the prevailing pressure, the excesswill be found in the free state. Most reservoir sands appear to contain somewater, and in the majority of fields the oil is trapped in the structure andheld over water. In certain conditions the entrapping water may advance intothe oil zone and displace the oil therefrom.
This paper describes in a qualitative manner some of the characteristics ofthe displacement of oil by either gas or water, with an attempt to elucidatesomewhat the mechanism by which such displacement is effected.
T.P. 1337