bluuebunny/crossref_metadata_2025_split huggingface dataset:
GeoMechanics Field Characterization of the Two Prolific U.S. Mid-West Gas Plays With Advanced Wire-Line Logging Tools
Authors: Abousleiman Younane , Tran Minh , Hoang Son , Ortega J. Alberto , Ulm Franz-J. 
Published: October 2009

Abstract
Woodford shale has recently emerged as a potential gas play in the U.S. Mid-continent, following in the footsteps of the Barnett shale. Profitable production from these formations relies on the success of horizontal well drilling and hydraulic fracturing design, which in turn depends greatly on knowledge about rock formation anisotropic elastic properties and pore pressure coefficients (poroelastic properties). In this paper, a suite of recently developed wire-line logs such as the Element Capture Spectroscopy (ECS) log, Sonic Scanner log, and porosity logs, were run on the Woodford and Barnett formations. The results were utilized to estimate the anisotropic elastic and poroelastic properties of these gas shale formations using the GeoGenome™ model, a theoretical upscaling model backed up with unique laboratory testing on field retrieved preserved shale samples at a scale that has never before been investigated; that is, observing mechanics from displacements as small as 100 nm to 100 μm, and maximum applied forces not even reaching 1000 μN. Comparison between laboratory Ultrasonic Pulse Velocity measured data, Sonic Scanner log data, and simulated data has shown excellent agreement, and thus confirmed the reliability of the GeoGenome upscaling model in obtaining shale anisotropic mechanical properties of which some parameters cannot be obtained even with the most advanced sonic log. In addition, a new technique was developed using nano-indentation to extract the Woodford shale mechanical and strength properties from drill-cuttings. The measured stiffnesses and compressibility on Woodford shale drill-cuttings-size chips have shown great potential for full mechanical characterization of rocks from just the drill-cuttings, which until recently were regarded as having little value for rock mechanical characterization besides some existing simple empirical correlations. This new shale testing technique will undoubtedly help the industry to significantly reduce the overhead associated with full core retrievals at great depths.
Minimizing Water Invasion in Shale Using Nanoparticles
Authors: Sensoy T. , Chenevert M. E. , Sharma Mukul M. 
Published: October 2009

Abstract
This paper presents data showing the positive impact of adding nanoparticles to water-based drilling muds and their effect on fluid penetration into hard and soft shale. Use of present-day water-based muds during drilling can produce fluid penetration from the mud into shale formations resulting in swelling and wellbore instability. The nanometer sized pore throat diameters of shales are too small for conventional drilling fluid particles to invade and build an internal or external mud cake.
Four field muds in contact with Atoka and Gulf of Mexico (GOM) shales were studied with and without the addition of nanoparticles. Penetration of fluids into the shales was shown to decrease dramatically when nanoparticles were properly sized and applied.
Results show that nanoparticles reduce the permeability of the Atoka shale by a factor of 5 to 50. Similar results are obtained for the GOM shale. When nanoparticles were used, water penetration into Atoka shale was reduced by 98% as compared to sea water.
Measurement of shale pore sizes and scanning electron micrographs of the Atoka shale taken after exposure to nanoparticle dispersions, show that the nanoparticles are indeed small enough to penetrate and plug the shale pores and pore throats. This plugging of pore throats by the use of nanoparticles offers a powerful and economically viable new solution for controlling wellbore stability problems in troublesome shales.
Sequestering Carbon Dioxide in a Closed Underground Volume
Authors: Economides M. J. , Ehlig-Economides C. A. 
Published: October 2009

Abstract
The capture and subsequent geologic sequestration of CO2 has been central to plans for managing CO2 produced by the combustion of fossil fuels. The magnitude of the task is overwhelming in both physical needs and cost, and it entails several components including capture, gathering and injection. The rate of injection per well and the cumulative volume of injection in a particular geologic formation are critical elements of the process.
Published reports on the potential for sequestration fail to address the necessity of storing CO2 in a closed system. Our calculations suggest that the volume of liquid or supercritical CO2 to be disposed cannot exceed more than about 1% of pore space. This will require from 5 to 20 times more underground reservoir volume than has been envisioned by many, and it renders geologic sequestration of CO2 a profoundly non-feasible option for the management of CO2 emissions.
Material balance modeling shows that CO2 injection in the liquid stage (larger mass) obeys an analog of the single-phase, liquid material balance, long-established in the petroleum industry for forecasting undersaturated oil recovery. The total volume that can be stored is a function of the initial reservoir pressure, the fracturing pressure of the formation or an adjoining layer, and CO2 and water compressibility and mobility values.
Further, published injection rates, based on displacement mechanisms assuming open aquifer conditions are totally erroneous because they fail to reconcile the fundamental difference between steady state, where the injection rate is constant, and pseudo-steady state where the injection rate will undergo exponential decline if the injection pressure exceeds an allowable value. A limited aquifer indicates a far larger number of required injection wells for a given mass of CO2 to be sequestered and/or a far larger reservoir volume than the former.
Comprehensive Model for Flow Behavior of High-Performance Fracture Completions
Authors: Zhang Y. , Marongiu-Porcu M. , Ehlig-Economides C. A. , Tosic S. , Economides M. J. 
Published: October 2009

Abstract
Experience shows that high-performance fractures (HPFs) may retain near unit flow efficiency (equivalent to zero skin in a vertical well) and rarely fail, even in highly deviated wells. This may be partly because overly simplistic models of the well flow behavior lead operators to maintain wells at lower production rates than could have been achieved for the same amount of injected proppant with a vertical well completion design. Rigorous models that account for widely accepted rock mechanics fundamentals indicate that the fracture to well connection is compromised in deviated wells and lead to questions whether the bulk of the flow to the well actually passes through the fracture.
Distributed volumetric sources are used in this model to rigorously model a wide variety of possible fracture geometries such as an expanded wellbore due to halo effect, flow strictly through the fracture, and combined flow to a single fracture and to remaining flowing perforations not connected to the fracture. The model also includes turbulent flow effects that may occur for radial flow conditions in the fracture plane or in the reservoir opposite wellbore sections not connected to the fracture as well as high velocity flow through the perforation tunnels. It also computes the effective flow area at the resulting face between the reservoir and the completion to check whether flow velocity exceeds conditions that would risk production of reservoir fines, and estimates the screen flow velocity based on the number of flowing perforations.
This comprehensive view of the HPF completion enables a thorough analysis of the risks of flowing the well at high rate. Field examples show that the new model better depicts the real field conditions in calculating the total skin, flow fractions and the flux for HPF completions in high rate gas and oil wells.
Complete inflow performance behavior for all likely flow patterns for HPF wells in oil and gas reservoirs is provided.
Improving Fidelity of Network Models for Drainage and Imbibition
Authors: Peng Yao , Prodanovic Maša , Bryant Steven L. 
Published: October 2009

Abstract
Network models are a powerful method for extracting macroscopic multiphase properties from microscopic information. All network models of capillarity-controlled displacements (drainage/imbibition) require critical curvatures for pore level events as input. Techniques that ensure accurate critical curvatures in these models are therefore valuable. We describe a novel method to verify the correct choice of curvatures: a pore-by-pore comparison of displacement events predicted by a network model with those computed directly in the original pore space. The latter are obtained from LSMPQS, our implementation of the level set method for tracking fluid/fluid menisci in arbitrary confining geometry. We examine the robustness of a new, convenient criterion to estimate the critical curvature for imbibition events, derived from observing instances of Melrose's mechanistic criterion during LSMPQS simulations in about 200 individual pores. We validate the approach by comparing predictions from large, finite networks and infinite-acting networks to measured drainage/imbibition curves.
A subset of a densely packed, disordered packing of spheres was used to test these concepts. More than 95% of the pores investigated have the same filled phase for network model and LSMPQS simulations at the drainage endpoint and more than 85% are the same at the imbibition endpoint. A smaller fraction (around 65%) matched in the vicinity of the percolation threshold, mainly because a small error in estimating critical curvatures in the network leads to a disproportionately large shift in the pressure-saturation curve. But the sequence of pore-filling events during drainage is very similar in the two cases. The new criterion for pore imbibition was also verified, as the imbibition curves for both simulations exhibit similar behavior, which in turn match experiments reported in the literature. The sequence of pore-filling events during imbibition differed for the network model and LSMPQS, however. This was primarily because the network model simulations did not account for coalescence of pendular rings.
Capillary pressure curves from infinite acting network models showed the same percolation threshold as traditional estimates, but a larger saturation of displaced phase was obtained at the drainage/imbibition endpoints. The larger residual nonwetting phase saturation (Snwr) is consistent with estimates of residual saturation in reservoirs from tracer tests, indicating that lab-scale measurements of this quantity are influenced by boundary effects not present in the field.
Interpretation of Well Test Data in Gas Condensate Deformable Formations
Authors: Shandrygin A. , Rudenko D. , Begar A. 
Published: October 2009

Abstract
The interpretation of WT data in gas condensate formation with stress sensitive rock is very complex problem due to simultaneous effect of several phenomena on fluids flow in the near wellbore area such as: "formation damage skin", non-Darcy flow effect, condensate bank and permeability changing due to rock deformation. In this case it's not possible to estimate the main reservoir properties and total skin with its components using only standard interpretation technique of the WT data. This problem can be solved on the basis of special approach of the joint treatment of the steady flow multirate test and pressure build up test data. The proposed WT data interpretation method allows to get the key formation parameters: "undamaged" formation permeability (permeability in area distant from well), permeability vs. formation pressure as exponential function, non-Darcy flow coefficient, total and "condensate bank" skins. Suggested approach was evaluated using synthetic production data for the reservoir model based on the Urengoyskoe field (Western Siberia, Russia) parameters.
Collaboration in Extracting More Oil in Mature Dual Completion Wells
Authors: Khalid M. Idham , Poit R. Elug , Jumaat M. Shafie 
Published: October 2009

Abstract
The offshore state of Sarawak in Malaysia contains many mature wells that were completed 20-30 years ago with dual-strings and multiple packers to exploit the many layers of sand packages. The wells that were designed to exploit the main sand packages are currently depleted and producing at high water cut. The operator is now considering ways of exploiting the smaller intermediate sand packages in these wells. In many cases, this requires oriented perforating through one completion string while avoiding shooting another completion string that is still producing. Oriented perforating using analog orienting devices that were previously deployed has many operational problems that on several occasions have led to abandoning jobs, and ultimately deferment of additional production. As such, this has led to many of these mature wells that require oriented perforating being left unexploited for many years. The arrival of a new digital orienting device is expected to open the path to better exploitation of the intermediate sand packages.
This paper is a case of deployment of this device for PETRONAS Carigali in Sarawak, Malaysia which required collaboration with the service contractor at many stages, from planning and characterizing the device responses in various completion configurations in Sarawak, to writing standard operational procedure and contingency planning, and to real-time decision making during operation.
The results of operation of this device on two wells in Sarawak are also presented, as is how the collaboration in the planning stages contributed to their successes.
While the success paves the way for future exploitation of the intermediate sand packages for PETRONAS Carigali, the exercise also provides a reference for similar operations in other places, from the point of collaboration and technicality of the service itself.
Seawater Desalination Using Excess Heat from GTL Process
Authors: Srivatsan Jagannath Saiyee , Linke Patrick , Amani Mahmood 
Published: October 2009

Abstract
Over the years, the increasing prices of crude oil and environmental issues have been the major factors for the development of GTL technology. With over 910 Tcf of natural gas reserves in Qatar (gas-in-place and recoverable resources), there is tremendous capacity for additional GTL plants in Qatar. Out of the global projected GTL production of 1.92 million B/d, Qatar alone already has planned to produce 696,000 B/d (36% of total global production). One of the efficient ways of using the exothermic heat from GTL is for desalination. This helps in reducing a large quantity of the fresh fuel to be used as energy input for desalination.
The need for this study is to investigate the availability of exothermic heat from the Gas-To-Liquids (GTL) process to desalinate seawater thereby producing substantial volumes for industrial and/or domestic sectors. This is performed by first designing a schematic base case model of the GTL operation using Aspen Plus. The quantity and quality of heat available from the cooling of the syngas and syncrude streams is used as the energy source for the desalination process. Both thermal desalination and reverse osmosis processes are considered to determine the optimal process for desalination. An integrated GTL-Desalination (GTL-D) process is later designed to compare the output ratio of the GTL-D as opposed to a standalone desalination process.
Intelligent Upscaling of Static and Dynamic Reservoir Properties
Authors: Gholami V. , Mohaghegh S. D. 
Published: October 2009

Abstract
Rock typing is an essential part of building geological model for an asset. Millions of dollars are invested in logs, core measurements, SCAL studies and geological interpretation that result in definition of different rock types. In most caes rock types that are identified in a reservoir do not have crisp boundaries and display overlapping characteristics. During the upscaling process, multiple rock types that have been identified in a high resolution geological (geo-cellular) model are approximated into a dominant rock type for any grid block in a reservoir simulation flow model.This defeats the original purpose of performing detail geological and petrophysical studies as far as reservoir flow models are concerned. The objective of this study is to develop a new upscaling methodology based on fuzzy set theory principles. Fuzzy rock typing refers to taking into account the inherent uncertainties and vagueness associated with rock typing in hydrocarbon bearing reservoirs.
In this paper a numerical simulator has been used as the control environment in order to set up multiple studies that would demonstrate the difference between using conventional approach of implementation of geological models in the reservoir flow simulation studies and the new approach that is the subject of this study. By using the numerical reservoir simulator as the control environment it is intended to study the complexities that exist in geological model at much higher resolution and then compare simulation in large grid blocks using two different approaches. The problem has been set up in the form of upscaling study.
First, the study was performed using conventional upscaling practices and then it was carried out using the proposed technique. The results then have been analyzed in order to demonstrate the difference between the two techniques and the advantages and disadvantages o f each have been identified.
This manuscript has been organized in several sections. In the literature review section the current practices in upscaling dynamic reservoir properties such as relative permeability and capillary pressure are reviewd as well as basic definitions of rock typing. A brief section on fuzzy set theory is also presented in this section. The problem is defined in more details and some background information is presented in the "Introduction" Section. The approaches used to perform the study are presented in the "Methodology" section. Details results are presented and discussed in the "Results & Discussion" section and the manuscript is completed providing some concluding remarks.
Nonlinear Sorption Kinetics and Surface Diffusion Effects on Gas Transport in Low-permeability Formations
Authors: Fathi E. , Akkutlu Yucel 
Published: October 2009

Abstract
In coals and shales, gas transport and storage are important for accurate prediction of production rates and for the consideration of subsurface greenhouse gas sequestration. They involve coupled fluid phenomena in porous medium including viscous flow, diffusive mass transport and adsorption. Standard approach to describe gas-matrix interactions is deterministic and neglects the effects of local spatial heterogeneities. Using an upscaling approach based on small perturbation theory, the authors have previously investigated the influence of small-scale heterogeneities in matrix porosity on Darcy flow and Fickian-type pore diffusion in the presence of linear non-equilibrium gas adsorption (Fathi and Akkutlu, 2009). They identified non-trivial macro-transport and -kinetics effects of the heterogeneity which significantly retard gas release from the matrix and influence the ultimate gas recovery adversely. The work was a unique fundamental approach for our understanding of the gas behavior in unconventional reservoirs; however, it was simplified and did not consider (i) the presence of nonlinear sorption kinetics and (ii) a transport mechanism for the adsorbed phase, i.e., surface (or solid) diffusion. In this paper, we incorporate the sorption nonlinearity and surface diffusion into their formulation and apply the same upscaling approach. Gas sorption involves the so-called Langmuir kinetics, which reduces to the well-known Langmuir isotherm in the equilibrium limit. It is found that the nonlinearity participates into both macro-transport and -kinetics, promoting primarily the surface diffusion effects. Whereras, the surface diffusion, although commonly ignored by the industry, brings an intricate nature to the gas release dynamics. Through macro-transport effect of the heterogeneity, it increases the ultimate gas recovery and, through the macro-kinetics effect of the heterogeneity, it decreases the time needed to reach the ultimate recovery significantly. As the consequence of these effects, it is shown that the gas-matrix system does not reach the equilibrium adsorption limit during any stage of the gas release.
Case Study of a Novel Hydraulic Fracturing Method that Maximizes Effective Hydraulic Fracture Length
Authors: Tudor Eric H. , Nevison Grant W. , Allen Sean , Pike Blaine 
Published: October 2009

Abstract
Effective fracture lengths are frequently observed to be much less than antcipated fracture lengths. This is seen in lower than expected production or evidenced in pressure transient analysis results. A precursor to the poor fracture performance is poor recovery of the fracturing fluid; often less than 50% is recovered during clean-up. In many reservoirs this unrecovered fracturing fluid remains immobile within the formation creating an obstruction to flow. This significantly compromises effective frac length and results in decreased production.
During the fracturing process and subsequent closure of the fracture, the bulk of the fracturing fluid invades the reservoir matrix along the fracture face, referred to as the "invaded zone". This fluid is forced into the reservoir by the significant pressure differential between fracturing pressure and reservoir pressure. Once in the matrix, removal of fluid from the invaded zone can be very difficult as it is held by relative permeability, irreducible saturation, and/or capillary pressure effects.
A novel hydraulic fracturing process using 100% liquefied petroleum gas (LPG) has demonstrated quick and complete fracture fluid recovery, significant production improvements and dramatically longer effective fracture lengths. The process gels the LPG for efficient fracture creation and proppant transport. With that there is no compromise in the fracture treatment placed when compared to conventional treatments. However, once the fracture treatment is complete and the viscosity of the gelled LPG is broken, the unique properties of LPG create an ideal fluid for complete cleanup. Removal of this fluid from the invaded zone is easily achieved; relative permeability effects, irreducible saturation behaviour and capillary pressure demands are eliminated. Complete recovery of the LPG is consistently demonstrated.
Fracturing with 100% gelled LPG was first completed in January 2008. By June 2009 over 210 fracture treatments had been completed. This new process has been applied to a wide range of formations from depths of 750 ft through to 11,500 ft. In this paper, short term technical evaluations, such as post fracture pressure transient analysis, are used to demonstrate the rapid cleanup and effective fracture lengths that approach anticipated fracture lengths. Long term actual production comparisons will be a focus on future papers as results become available.