bluuebunny/crossref_metadata_2025_split huggingface dataset:
Modeling Chemically Induced Pore Pressure Alterations in Near Wellbore Region of Shale Formations
Authors: Huang Lu , Yu Mengjiao , Miska Stefan , Takach Nicholas , Bloys J. B. 
Published: December 2011

Abstract
Instability issues often occur when water-based muds are applied to shale formations. Failure to predict the pore pressure accurately has been widely accepted as one of the major reasons causing shale instability. Water activity is a key factor to control the pore fluid moving in and out of the formation due to osmotic effects. Ideal and single-solute models have been developed in the past to predict the pore pressure by considering chemical osmotic effects. However, due to their complex nature, pore fluids/drilling fluids rarely behave as ideal solutions. A new model has been developed to predict pore pressure in shale formations that takes into account the non-ideality and multiple solutes of both drilling fluid and pore fluid. Transient pore pressure profiles and water activity are obtained from the coupled equations developed in this study. A Shale-Fluid Interaction Testing Cell (SFITC) has been developed in this study to test the interaction between the drilling fluid and the pore fluid. Parameters involved in the model, such as hydraulic conductivity, membrane efficiency and ion diffusion rate can be obtained through experimental data curve fitting. Model predictions have been compared with lab data and good agreement has been achieved. Water activity is found to be crucial for pore pressure control in shale formations. Simulation results explain the fact that salinity of drilling fluids has to be controlled in order to achieve shale stability. Results of this study can benefit drilling fluid design. Shale instability can be reduced by "balancing" the water activities of shale and drilling fluid. This can be achieved through changing the type of solutes and their concentrations based on information of the initial water activity of the shale. Wellbore stability models can obtain more accurate results by including the proposed pore pressure propagation model, which considers drilling fluid-induced chemical osmotic in-situ stress.
Numerical Dispersion Impact on Local Mixing in Heterogeneous Reservoirs
Authors: Rouzbeh Ghanbarnezhad M. 
Published: December 2011

Abstract
Dispersive mixing degrades field-scale miscible displacements through dilution of the injected solvent. This paper examines how local mixing owing to pore scale heterogeneity compares with the apparent mixing caused by numerical dispersion in heterogeneous permeable media. The numerical dispersion is associated with the truncation error inevitably introduced in finite difference approximations of the conservation equations.
In this study, the finite difference form of the convection-dispersion equation is derived to determine the numerical dispersion coefficients when flow velocity varies with distance. In addition, a simulation approach is used to evaluate local mixing in heterogeneous permeable media. The simulation models consist of an injector and a producer located at the ends of a two-dimensional grid. The simulations are performed with a fixed total dispersivity and different ratios of numerical to physical dispersivities. The local mixing for each grid block is determined through matching the concentration history to solution of the convection-dispersion equation.
Furthermore, spatial distribution of the local mixing caused by dissimilar sources of dispersivity is examined; geostatistics functions (the autocorrelation coefficient function and the semivariance) are determined for different separation distances. Autocorrelogram and variogram plots illustrate the variation of dispersivity in the longitudinal direction.
It turns out that the off-diagonal elements of the numerical dispersivity tensor are twice as large as in homogeneous reservoirs when the velocity changes with distance. Furthermore, the results indicate that the local mixing and the corresponding spatial distributions are considerably different when dissimilar ratios of numerical to physical are implemented. The different spatial distribution of local mixing explains why the growth of mixing zone is not characterized properly when considerable numerical dispersion is present. In addition, the results suggest that adjusting the size of grid blocks to account for the physical dispersivity is not appropriate in heterogeneous permeable media.
Channel Hydraulic Fracturing and its Applicability in the Marcellus Shale
Authors: Ajayi Babatunde , Walker Kirby , Wutherich Kevin , Sink John 
Published: December 2011

Abstract
Gas wells in the Marcellus shale are usually completed with a hydraulic fracture treatment in order to create a conductive proppant pack for fluid flow to the wellbore thus effectively increasing well productivity. A novel hydraulic fracture technique which creates a network of open channels within the created fracture has recently been introduced to the oil and gas industry with over 1400 successful treatment stages pumped in other ultra-low permeability, gas-bearing unconventional reservoirs. Channel fracturing boasts higher fracture conductivity and better fracture cleanup amongst its other claims. This paper reviews the applicability of the novel hydraulic fracturing technique in the Marcellus shale and details a case study investigating the possible production gains that may be obtained when channel fracturing is applied in this play.
This feasibility study briefly describes the Channel Hydraulic Fracturing technique and investigates the geophysical properties of the Marcellus shale to see if Channel fracturing is applicable in the play. The methods employed involves analyzing over 160 well logs spread across the Marcellus shale in order to create a grid map of counties and regions within the Marcellus Shale area that meet the criteria required for the applicability of the new technology. The technique is then compared to conventional hydraulic fracturing by reviewing initial production results from a Marcellus well with a conventional hydraulic fracture and performing production analysis and history matching using a production analysis software package. The conventional hydraulic fracture parameters are then replaced with channel fracturing parameters to obtain incremental production estimates.
The results of the study indicate that the Channel Fracturing technique is applicable without in most areas of the Marcellus shale play. The results of the simulation and case study show increased gas production from the new technique over conventional fracturing methods.
Perforation Shaped Charge Design for Shale Produces Improved Tunnel Geometry
Authors: Hardesty J. , Clark N. , Bell M. R. , Zaleski T. 
Published: December 2011

Abstract
The perforation of wellbore casing is a critical step in establishing communication between the wellbore and formations of interest. The effectiveness of this communication is dependent upon both the geometry of the perforations and the permeability distribution of altered material surrounding them. To date, our understanding and modeling of this geometry and permeability distribution has been limited to simple representations consisting of cone-shaped tunnels surrounded by a damaged layer exhibiting a constant, reduced permeability - typically of constant thickness. These models are based mainly on performance evaluations conducted in cement targets, and less frequently upon performance tests with stressed sandstone targets. This methodology influences our thinking regarding many post perforation process, including fracture completions, but breaks down when estimating perforation performance in shale formations.
This paper describes a body of experimental work with perforation simulation in a state of the art API RP-19B Section 4 facility. Tests are conducted in shale targets with a variety of shaped charge designs. The perforation tunnels are evaluated for geometry and performance using next generation CT scan imaging techniques. The results of this study show that perforation geometry produced in shale targets is significantly different from that produced in cement or sandstone targets commonly used to estimate perforation performance and that changes in shaped charge design can produce significant geometry improvements not recognizable by selection and evaluation in conventional targets.
In addition a field case comprised of 14 wells and 81 stimulation stages is presented demonstrating the potential improvement that can be obtained by using shaped charges designed for maximum performance in shale formations. When comparing wells perforated with improved charges to conventionally perforated offsets, a reduction in breakdown pressure gradient of between 13% and 29% is observed. Subsequent treating pressures are reduced by 6% to 15%.
Improved Predictions of Porosity from Microresistivity Logs in a Mature Field through Incorporation of Pore Typing
Authors: Teh Woan Jing , Willhite GP , Doveton JH , Tsau JS 
Published: December 2011

Abstract
The value of m is critical in making estimates of water saturation. "Rule of thumb" values of cementation might lead to errors in water saturation on either the optimistic or the pessimistic side. In a mature field, developed during the 1950s, no porosity logs were available from sources other than the flushed zone resistivity Rxo. The microresistivity porosity was calibrated with the core porosity to yield an accurate estimate of the porosity. However, the procedure of calibrating the porosity with Rxo for a linear regression model may not be sufficiently predictive without an understanding of the pore types in the reservoir interval. A thorough investigation of the pore types, based on the lithofacies description obtained from the core analysis, and its role in obtaining a good estimate of porosity is demonstrated in the Ogallah field. Therefore, the objective of this paper is to separate the porosity-microlog data into pore-type based zones with characteristic cementation exponents (m) in this multi-petrotype reservoir with a complex mixture of Arbuckle dolomite and sandstone rock.
The rock types in the Ogallah contain interparticle/intercrystalline, vugs and fractures distributed through the rock-facies, which influence the values of cementation factor. Rock fabric numbers and flow zone indices have been identified for classification of dolomite and sandstone, respectively. The analysis brings out characteristic cementation factors for distinct pore types in the Arbuckle rock. The analysis results also compliment the petrofacies delineation using discrimant analysis in this complicated rock layout as a quality control of the statistical application. The comparison between the predicted and core porosities shows a significant improvement over using a single m-value for carbonates and sandstones which will lead to improved description of a matured field.
The Impact of Stress and Formation Properties on the Outcome of Fracture Operations in Horizontal Shale Wells
Authors: Bilgesu H. I. , Yusuf A. 
Published: December 2011

Abstract
The natural gas production is gaining importance as a clean source of energy. Several potential sources exist for gas production in the Appalachian Basin with the Marcellus shale being the largest resource in the U.S. This covers several states in the Eastern U.S. and plays a vital role in the future of gas production. As a result operators are interested in the development of the shale resources mostly with multi-stage fractures using a horizontal well. However, the lack of commercially available information on well and treatment designs is rather vague. This information is critical in the determination of economics of gas production from shale wells.
In this study, simulations have been conducted to determine the gas production from horizontal shale wells when limited data is used in the design of fracturing operations. Some of the parameters studied include horizontal and vertical stresses, the amount of fracture stages and formation properties along with others. The same treatment can yield different fracture geometry due to changes in formation properties; however, the gas production values after a single fracture treatment were similar for cases considered in this study.
Successful Geosteering in Low Resistivity Contrast Reservoirs of the Permian Basin
Authors: Kok Jeffrey , DeJarnett Jeff , Geary Daniel , Vauter Eric 
Published: December 2011

Abstract
The Permian Basin of West Texas and New Mexico is a prolific brownfield that produces from numerous clastic and carbonate horizons. Some of these reservoirs are composed of several separate thin tight sands ranging from 6 to 11 feet. Historically, these thin bed formations were bypassed because of lack of production in vertical wells. To economically exploit hydrocarbon reserves from these thin beds, maximum reservoir contact within a single layer or commingled across reservoir layers off a horizontal well path is necessary. To maintain or steer the well within these thin reservoirs, distinct log responses across the reservoir is needed for lateral correlations and well trajectory steering. Unfortunately in the thin reservoir realms such as those encountered in the Permian Basin, a lack of contrast in log measurements, such as gamma ray and resistivity, often results in poor geosteering decisions with the consequence of high costs in well construction. Advances in horizontal and LWD technology now offers real-time placement accuracy using proactive bed boundary mapping technology that incorporates a sophisticated arrangements of resistivity transmitter-receiver arrays. It is well understood in the technical domain that log measurements require a degree of change in formation log response for steering applications. However, in low log measurement contrast reservoirs, deep directional curve measurements are currently the optimum alternative for well positioning interpretation.
Pressure-Pressure Deconvolution Analysis of Multiwell-Interference and Interval-Pressure-Transient Tests
Authors: Onur M.. , Ayan C.. , Kuchuk F.J.. J. 
Published: December 2011

Summary
This paper investigates the use of pressure-pressure (p-p) deconvolution for interpretation of conventional multiwall-interference and wireline-formation-tester (WFT) interval pressure-transient tests (IPTTs). The investigation is limited to interference tests for which only a single source/sink well exists in a single-layer system. It is shown that the recent deconvolution algorithms developed for pressure-rate (p-r) deconvolution based on the same assumptions (i.e., a single source/ sink well) can also be used for performing p-p deconvolution by simply replacing the rate data in p-r deconvolution algorithms by the pressure data recorded at a source/sink location or at one of the observation locations. We apply p-p deconvolution to both synthetic and field-transient test data sets from IPTTs and multiwall-interference tests. Specifically, we investigate the applicability of p-p deconvolution for inconsistent data sets, where wellbore storage and skin may change from one flow period to another one. The results show that the impulse functions deconvolved from p-p deconvolution have signatures for various flow regimes (e.g., radial, spherical, linear) that are similar to from p-r deconvolution except from the pseudosteady-state (pss)-flow regime. Therefore, p-p deconvolution can also be used for model identification in the similar way based on p-r deconvolution algorithms, without requiring the flow-rate information.
Water Mixing During Waterflood Oil Recovery: The Effect of Initial Water Saturation
Authors: Graue Arne , Fernø Martin A. , Moe Robert W. , Baldwin Bernard A. , Needham Riley 
Published: December 2011

SummaryThis work studies the mixing of injected water and in-situ water during waterfloods and demonstrates that the mixing process is sensitive to the initial water saturation. The results illustrate differences between a waterflooded zone and a preflooded zone during, for example, water-based EOR displacement processes. The mixing of in-situ, or connate, water and injected water during laboratory waterfloods in a strongly water-wet chalk core sample was determined at different initial water saturations. Dynamic 1D fluid-saturation profiles were determined with nuclear-tracer imaging (NTI) during waterfloods, distinguishing between the oil phase, connate water, and injected water. The mixing of connate and injected water during waterfloods, with the presence of an oil phase, resulted in a displacement of all connate water from the core plug. During displacement, connate water banked in front of the injecting water, separating (or partially separating) the injected water from the mobile oil phase. This may impact the ability of chemicals dissolved in the injected water to contact the oil during secondary recovery and EOR processes. The effect of the connate-water-bank separation was sensitive to the initial water saturation (Swi). The time difference between breakthrough of connate water and breakthrough of injected water at the outlet showed a linear correlation to the initial water saturation Swi. The results obtained in chalk confirmed earlier findings in sandpacks (Brown 1957) and thus demonstrated the generality in the results.
Wettability Studies Using Low-Salinity Water in Sandstone Reservoirs
Authors: Alotaibi M.B.. B. , Nasralla R.A.. A. , Nasr-El-Din H.A.. A. 
Published: December 2011

Summary
The ionic strength of injection water can have a major impact on oil recovery resulting from the use of low-salinity brines. Understanding how the water and oil chemistry affects the final recovery from a physicochemical point of view is necessary in order to optimize low-salinity waterflooding. It is clear from the literature that wettability is a key factor in achieving the low-salinity effect. Optimum ionic strength and conditions for low-salinity flooding with respect to wettability are still uncertain.
In this paper, we studied fluid/rock interactions at different salinity levels and elevated temperature conditions in terms of wettability and surface charge. Wettability is determined by a high-temperature/high-pressure (HT/HP) contact-angle method and zeta-potential technique. Outcrop rocks and stock-tank crude-oil samples were used in all experiments. Synthetic formation brine water, aquifer water, and seawater were evaluated under high-pressure conditions. Zeta potential of sandstone rocks and selected clay minerals was measured as a function of ionic strength.
Wettability of oil/brine/sandstone systems depends on salinity, temperature, and rock mineralogy. Using aquifer water in Berea sandstone improved the wettability toward a water-wet condition. The same aquifer water behaved in a different way when a different sandstone surface was tested. In Scioto sandstone, aquifer water changed the wettability to a neutral state. Low-salinity water expanded the double-layer thickness and eventually increased the zeta-potential magnitude. As a result of this expansion, it provides a greater opportunity to alter the wettability and enhance oil recovery. This study indicates that clay content in sandstone rocks can significantly alter the wettability either toward water-wet or intermediate. On the basis of the results obtained from this study, it is clear that low-salinity waterflooding can improve oil recovery in the field.
Successful Laboratory Testing of Practical Methods of Hydraulic-Control-System Failure Diagnosis Using Valve Signatures
Authors: An Hailing , Tanju Baha 
Published: December 2011

Summary
The two hydraulic-diagnostic methods detailed in this paper can monitor the "health" of a subsea hydraulic-control system, diagnose or predict a system problem (particularly leaking or clogging problems), and locate its source by using readily available valve-signature data.
The methods were tested in a laboratory environment using a hydraulic system with simulated clogging and leaking mechanisms. Leak detection was performed using both signature-matching and mass-balance methods. The results showed a mean accuracy of 93% for mass-balance method and 82% for the signature-matching method. Clog detection by signature matching showed high accuracy in the controlled laboratory condition. The difference between the simulated and actual clogging is within 1%.
The methods provide a monitoring tool for detecting and locating potential leaks, blockages, and other system changes or anomalies, which could be used to estimate the potential high cost of intervention, possible downtime, and lost revenue.
A Comprehensive Model of High-Rate Matrix-Acid Stimulation for Long Horizontal Wells in Carbonate Reservoirs: Part II—Wellbore/Reservoir Coupled-Flow Modeling and Field Application
Authors: Furui K.. , Burton R.C.. C. , Burkhead D.W.. W. , Abdelmalek N.A.. A. , Hill A.D.. D. , Zhu D.. , Nozaki M.. 
Published: December 2011

SummarySuccessful acid stimulation of long-horizontal-well intervals in carbonate reservoirs requires effective acid distribution along the entire reservoir length. Such treatments also require large volumes of acid and seawater/brine injection at sufficiently high injection rates to drive the acid wormholes deep into the reservoir. Under these flowing conditions, significantly large tubing friction loss is anticipated unless optimal friction reducer performance in the tubing is maintained throughout the pumping operation. Because prediction of wormhole penetration and corresponding skin factor depends on analysis of downhole-injection pressures at the reservoir face, it is crucial to properly account for these hydrostatic and friction changes prior to evaluation of wormhole length and skin factor.In this study, an integrated flow model has been developed to predict the wellbore-pressure profile and wormhole distribution by tracking the movement of the acid in the wellbore and the formation. The wellbore-flow model is based on steady-state, 1D, pressure-based nodal method. The segmented wellbore in the reservoir interval is then coupled with analytical transient reservoir-flow models. The wormhole propagation in the formation is calculated based on the modified Buijse-Glasbergen correlation and upscaling model developed in our earlier work. The resultant wormholing skin factor is calculated by simulating and updating the changing well injectivity along the entire injection interval at every timestep. The model developed in this work is applicable for both fully completed wells (i.e., radial flow) and selectively completed perforation-cluster wells (i.e., spherical flow) typically employed in carbonate reservoirs.Analysis of injection rates and pressures during acid treatment provides engineers with a way to determine the varying injectivity and tubing friction as stimulation proceeds. The model presented here can be used as a forward model for analyzing real-time treatment rate and pressure histories and can also be used to review past treatments to improve future treatment designs. Using actual field-stimulation data, we also discuss key elements to successful stimulation planning and the diagnosis of matrix-acid treatments to achieve effective wormhole coverage for horizontal completions in carbonate formations.
Discussion of Economic Foundations of Valuation Discounts
Authors: Macnaughton Alan 
Published: December 2011

The purpose of the Sansing (1999) paper is to bring some rigor to the fuzzy and contentious area of valuation discounts. This is worthwhile as valuations are seldom dispassionate searches for the truth. Sometimes the taxpayer's goal is to inflate the value, as in the case of a charitable donation; in other situations, such as for estate and gift taxes, the desire is to obtain a low value.
The first part of the discussion considers discounts for lack of marketability, while the second part considers minority discounts and integrates the two types.