bluuebunny/crossref_metadata_2025_split huggingface dataset:
Experimental PVT Property Analyses for Athabasca Bitumen
Authors: Ashrafi Mohammad , Souraki Yaser , Karimaie Hassan , Torsaeter Ole , Bjorkvik Bard J. 
Published: December 2011

Abstract
Extra heavy oil and bitumen reservoirs constitute huge volumes around the world and are attracting attention as alternative energy resources while the light oil reserves diminish. Thermal recovery and steam based methods are the most widely used recovery methods applicable to these highly viscous deposits. Study of steam injection in porous media containing viscous oil requires a good understanding of the physical properties of both reservoir rock and fluid. In particular, there are some bitumen properties that are needed for simulation studies and the most reliable source for these data is laboratory tests. This paper presents experimental study of some PVT properties of Athabasca crude oil to help provide input data for further numerical studies.
Viscosity of Athabasca heavy crude was measured using a rotational viscometer up to 300 °C. This viscosity data is a more reliable input for simulation purposes. Athabasca oil was characterized by gas chromatography analysis to C39+. No significant amount of components lighter than C9 was observed. Whole sample molar mass was measured to 534 g/mol by cryoscopy. Density at standard conditions of 1 atm and 60 °F was measured to 1.0129 g/cm3 by a density measuring cell. Density and molar mass of the C39+ fraction were also determined. Density measurements were performed in the temperature range 120–195 °C as well where the density was found to vary in the range 0.95–0.90 g/cm3. A formula was derived based on experimental density data to predict Athabasca bitumen density in the temperature and pressure range studied. The interfacial tension between oil and steam was measured in the temperature range 120–220 °C by the pendant drop method. The interfacial tension was determined to be between 25 and 18 mN/m with a decreasing trend in the temperature range studied. The results presented here can be used as reference data for studies related to Athabasca bitumen.
Microseismic and Microscopic Analysis of Laboratory Induced Hydraulic Fractures
Authors: Chitrala Yashwanth , Moreno Camilo , Sondergeld Carl , Rai Chandra 
Published: December 2011

Abstract
Microseismic (MS) monitoring of hydraulic fractures using either the downhole or surface geophones has become a common practice. The same setup may be used for the multi-stage fractures. The main limitations in using these data to understand hydraulic fracturing results are: the sensor location which is far away from the source, limited azimuthal coverage and inadequate velocity models. Analysis becomes more complex when we start dealing with anisotropic reservoirs. Typically the service companies produce the spatial and temporal plots of hypocenters without estimates of uncertainty leading the engineer to believe the hypocenter locations are exact. The hypocenter location problem becomes more complex in anisotropic shale reservoirs. Hypocenter locations are often determined from the arrival times of P-wave and S-waves and a known velocity model. The difference in the velocity structure and the complex fracture network make accurate fracture mapping difficult. In this paper, we report on a series of laboratory hydraulic fracturing studies performed on sandstone and a strongly foliated metamorphic rock, pyrophyllite. Microseismic events associated with the hydraulic fracturing are dominated by shear failure; fracture orientation is controlled as predicted by applied stresses in isotropic materials. However, in anisotropic materials the hydraulic fracture direction is influenced by the magnitude of anisotropy but is predictable when the anisotropic elastic constants are known. Visual evidence supports the hypocenter locations and focal mechanism determinations. Scanning Electron Microscope (SEM) observations reveal the nonlinear and nonplanar nature of the induced fractures. The fracture trace confirms the wider aperture at the injection point and the frequent occurrence of the terminations and bifurcations farther along the fracture front.
Fracture Treatment Optimization Via Points of Diminishing Return as Determined by Seismic Moment Tensor Inversion
Authors: Mace Kaitlyn , Urbancic Ted , Baig Adam 
Published: December 2011

Abstract
We introduce the concept of Fracture Treatment Optimization (FTO) to find and analyze the Point of Diminishing Return (PDR) of stimulations. The approach is based upon locating the opening and closing points of fractures as identified through Seismic Moment Tensor Inversion (SMTI) analyses of microseismic data collected during treatments. By using SMTI data, it is postulated that the size of a treatment, the proppant concentrations and amounts, types of fluid pumped and amounts, the rates of treatment, and disposition of the fracture network may be analyzed to determine if they are optimal for the formation and the stress conditions of each individual fracture stage. As described, FTO is performed as a post-treatment approach to characterize the effectiveness of the treatment process. The PDR is identified by analyzing the SMTI data for each event in time and compared to the fracture treatment data. We show, through example, how the SMTI data can be used to establish when the transition between fractures with opening components of failure and those including significant closure components of failure. We suggest that these states are indicative of reaching a PDR thereby allowing for changes to the treatment to be considered. In the examples provided, we identify apparent PDRs due to leakoff dominated pad stages which are too large and when proppant is added too late in the stage. Additional PDRs are identified in the treatment when an energy balance has been reached, where leakoff and fluid injection is at equilibrium. At this point we suggest that introducing a change in energy or proppant concentrations can optimize the treatment. This empirical optimization allows for potentially more economic and efficient stimulations in subsequent hydraulic fracture treatments in the field.
Porosity and Permeability Changes in Sandstones and Carbonates Under Stress and Their Correlation to Rock Texture
Authors: Petunin V. V. , Yin X. , Tutuncu A. N. 
Published: December 2011

Abstract
The porosity and permeability of carbonate and sandstone cores were measured using a CMS-300 permeameter under a variety of stresses. Stress-permeability correlations showed significant variations with rock type. Porosity decay was similar between the rock types. The difference in the stress-permeability behaviors is explained by the difference in the pore structure.
Permeability loss during reservoir depressurization has important consequences on production. Laboratory quantification of stress-dependent permeability conducted in this study provided useful data for reservoir models. In addition, the correlation between stress-permeability behavior and rock type is helpful in establishing a bridge between microscopic structure and geomechanics.
In sandstone cores, the permeability decayed by 10–20% with increasing stress while the porosity decreased by about 3%, similar to what is expected from a Carman-Kozeny-type correlation. In some carbonate cores tested, the permeability was altered by an order of magnitude with the same porosity reduction. Cores with artificial fractures behaved similarly to un-fractured carbonates. These results indicate that the porosity in carbonates can be divided into a conductive portion that controls the permeability through the Carman-Kozeny equation, and a non-conductive (vuggy) portion that has limited effect on fluid flow, similar to the division between fracture porosity and matrix porosity in fractured rocks. The porosity-permeability relationship of carbonates was used to separate the conductive and non-conductive (vuggy) porosities. The vugginess of carbonate samples were projected to be 25–90% of the total effective porosity. Microscopic imaging shows favorable initial agreement with model projections.
Reservoir rock properties are not static when they are being produced. Instead, pores change their shapes and sizes with varying stress conditions. Understanding those changes are valuable in their own right but this geomechanical response also indicates important features of the rock. This research not only characterized the stress-permeability behaviors of sandstone and carbonates, but also successfully correlated them to their characteristic texture. The method of characterization of vugginess through a geomechanical test is new, and this principle can be applied to fractured rock samples to find not only the compressibility of rock but also the fracture and matrix porosities.
Shale Reservoir Properties from Digital Rock Physics
Authors: Walls Joel D. , Diaz Elizabeth 
Published: December 2011

Abstract
A majority of the whole core samples recovered in the US today come from shale (mudstone) reservoirs. A primary reason for so much shale coring is that shale petrophysical models require rigorous core calibration to provide reliable data for reservoir quality, hydrocarbon-in-place, and hydraulic fracturing potential. However, the uncertainty in interpreting shale well log data is sometimes matched or exceeded by the uncertainty observed in traditional methods of analyzing core samples. Most commercial core analysis methods in use today were developed decades ago for sandstones and carbonates exceeding 1 millidarcy in permeability. High quality organic-rich shale on the other hand is usually lower than 0.001 millidarcy. This extreme low permeability creates substantial challenges for existing methods and has contributed to the rapid rise of a new approach to reservoir evaluation called Digital Rock Physics or DRP.
DRP merges three key technologies that have evolved rapidly over the last decade. One is a high-resolution diagnostic imaging method that permits detailed examination of the internal structure of rock samples over a wide range of scales. The second is advanced numerical methods for simulating complex physical phenomenon and the third is high speed, massively parallel computation using powerful graphical processing units (GPU’s) that were originally developed for computer gaming and animation.
Based on pore-scale images from a wide range of organic shales, it can be seen that organic material is present in a variety of forms. Three primary forms, non-porous, spongy, and pendular are commonly observed. Non-porous organic components fill all of the available non-mineral space leaving virtually no porosity or fluid flow path. Porous or "spongy" organic material is commonly encountered in thermally mature gas shales. Pendular organic material appears to fill the small inter-granular and grain contact regions, leaving open pore space in the larger voids. These pore types are largely controlled by kerogen type and thermal maturity, and they exert large influence on the porosity, permeability, and overall shale reservoir quality.
Shear Dilatancy in Unconsolidated Laboratory Samples Improves Relative Permeability Performance
Authors: Khan Hasnain A. , Olson Jon E. , Holder Jon 
Published: December 2011

Abstract
Steam Assisted Gravity Drainage (SAGD) can cause dilatant shear failure in unconsolidated heavy oil reservoirs. Our experimental work documents changes induced by such shear failure in absolute permeability, relative permeability to oil and water, and residual saturations. Tests were performed on 2 inch diameter synthetic specimens made from lower fine to medium grain size Ottawa sand formed with wet vibration to an initial porosity of about 32%. Loading paths included triaxial compression and radial extension. Axial and volumetric strains were measured directly during deformation, and single and two phase permeability tests were executed at axial strains of 1 to 10%. Triaxial compression tests followed a path of increasing mean stress (under constant confining stress) while radial extension tests provided a decreasing mean stress loading path (reducing confining stress under constant axial stress). The relative permeability was determined by the unsteady state method for relative permeability endpoint assessment. Results show similar absolute permeability trends to those published by others, but our multiphase measurements appear unique. Relative permeabilities are more strongly influenced by shearing, with water relative permeabilities being increase by as much as a factor of 2. The effect seems to be slightly greater for finer grain sand than for the medium grain size. Absolute permeability changes were greatest for the samples with the lowest initial porosity, which would include those that were poorer sorted. Poorer sorting of the sand pack seems to reduce the impact on relative permeability changes, however. Residual oil saturations were reduced from 0.28 to 0.13 in the lower fine Ottawa sample, suggesting the possibility for significant improvement in oil recovery when the sand is sheared. During triaxial testing, it was interesting to note that at 50 psi effective confining stress, absolute permeability increased with shearing, but at 200 psi effective confining stress, absolute permeability was reduced, even though the volumetric strain was still dilatant. In addition to providing new data on the magnitude of absolute permeability and multiphase flow properties for unconsolidated sands, this paper also demonstrates that dilatant shear failure does not guarantee increased flow capacity for such rocks.
Bayesian Probabilistic Decline Curve Analysis Quantifies Shale Gas Reserves Uncertainty
Authors: Gong Xinglai , Gonzalez Raul , McVay Duane , Hart Jeff 
Published: December 2011

Abstract
Several analytical decline curve models have been developed recently for shale gas wells (Anderson et al. 2010; Ilk et al. 2008; Valko and Lee 2010). However, despite the considerable uncertainty associated with forecasting shale gas production, these authors either do not quantify the reserves uncertainty in shale gas wells or fail to demonstrate that their probabilistic forecasts are well calibrated. Jochen and Spivey (1996) and Cheng et al.(2010) developed bootstrap methods that can generate probabilistic decline forecasts and quantify reserves uncertainty. Forecasts with the Modified Bootstrap Method (Cheng et al. 2010) provide good coverage of the true reserves. However, it is not time efficient because it requires hundreds of Newton iterations for each well. In this work, we introduce a Bayesian methodology for probabilistic decline curve analysis that quantifies reserves uncertainty reliably, quickly, and without modifying the historical production data. We analyzed 167 horizontal gas wells with more than 7 years of production in the Barnett shale to validate the methodology.
In this Bayesian methodology, the decline curve parameters qi,Di, and b are assumed to be random variables instead of parameters to be modified to obtain a best fit. A Markov chain of the decline curve parameters is constructed using MCMC with the Metropolis algorithm. In the test of 167 Barnett shale horizontal gas wells, we assume that the first half of production is known and the second half of production is unknown and acts as "future production." Approximately 85% of the 167 wells’ "future production" falls in the range of P90 and P10 reserves generated by this Bayesian methodology, indicating the method is well calibrated, and the Bayesian method is 13 times faster than the modified bootstrap method.
The proposed Bayesian methodology provides a means to generate probabilistic decline curve forecasts and quantify the reserves uncertainty in shale gas plays quickly and reliably. This Bayesian methodology can also be applied with other analytical decline curve models if desired.
Measuring the Impact of Geomechanical Heterogeneity in Organic Shales on Hydraulic Fracture Initiation and Propagation
Authors: Waters George , Zhao Ruhao 
Published: December 2011

Abstract
The placement of multiple hydraulic fractures along cased and cemented horizontal wellbores drilled in the direction of minimum horizontal stress is the most common completion methodology used in the development of organic shales today. Multiple perforation clusters are included in each stimulation treatment to optimize time and efficiency. This does not necessarily result in optimized productivity as many perforation clusters are frequently determined not to be contributing to production when these wellbores are evaluated with horizontal production logs.
The ability to initiate, propagate and place proppant through the near-well region of a hydraulic fracture is a function of stresses around the borehole and the orientation of the borehole relative to the principle stress field. The near-well stresses are influenced by the anisotropic geomechanical medium pervasive in organic shales. This anisotropy can dramatically alter the stress field and must be taken into account if productivity is to be optimized along a horizontal wellbore.
Field data from the Barnett Shale is evaluated to estimate the impact of this anisotropy on the ability to initiate and place hydraulic fractures through the near-well region. Fracture initiation and near-well closure pressures are measured and compared to those predicted by accounting for geomechanical anisotropy. These results are used to develop guidelines for effective perforation placement. Such techniques can be used to improve well productivity.
Novel Wellbore Strengthening Enables Drilling of Exploration Well in a Highly Depleted Formation
Authors: Friday Otutu 
Published: December 2011

Abstract
Operators all over the world are still facing the challenge of having to drill through highly pressure depleted formations in order to drill to lower lying hydrocarbon bearing zones especially in terms of wellbore stability and loss circulation. Stability of boreholes in these scenarios requires a careful consideration of in-situ stresses, rock strength, pore pressure, wellbore fluid pressure and drilling fluid characteristics. Managing lost circulation with stability offormations is one of the most difficult scenarios that needs proper engineering. Before a depleted zone can be cased-off, it has to be successfully drilled. Drilling through highly depleted sands can result in problems such as lost circulation, differential sticking, difficult logging and/or not being able to reach the well objective depth, wellbore instability resulting in significant and expensive non-productive time (NPT) and costly remediation process, in addition to the loss of costly mineral oil-based mud used for drilling.
Remedies such as squeezes, cement plugs, expandable liner and casing while drilling can be costly solutions and are not always successful.
Key factors in the successful drilling of study wells included special drilling fluid design, rock mechanics study, pro-active use of bore hole strengthening technology, integration of supplier and operator expertise, and excellent communication between all parties involved.
The study showed that enhanced formation strength can allow sufficient tolerance to overbalance pressure leading to the use of higher mud weight due to the widening of mud weight window especially when an exploration objective is to be drilled below depleted formations.
This paper presents the result of the use of a novel system used in improving the formation strength characteristics in a depleted environment.
C7+ Characterization of Heavy Oil Based on Crude Assay Data
Authors: Ghasemi M. , Alavian S. A. , Whitson C. H. 
Published: December 2011

Abstract
The description of heptanes and heavier components (C7+) in reservoir fluids can be important for equation of state (EOS) predictions of phase and volumetric behavior. This paper describes a procedure for C7+ characterization of heavy oil based on crude assay data which are typically measured for refining and marketing applications.
C7+ characterization is defined as (1) modeling the molar distribution that quantifies molar (mass) amounts and molecular weights of discrete plus fractions, (2) estimating specific gravity and normal boiling point of plus fractions, and (3) estimating EOS and viscosity-model parameters Tc, pc, ω, Vc, s (volume shift) and binary interaction parameters (BIPs) kij of plus fractions.
From crude assay data, we use the mass fractions and overall sample molecular weight to determine the parameters for gamma molar distribution parameters – shape (α), lower bound (η) and average plus molecular weight (Mo) in the gamma distribution model. The molar distribution model, together with measured assay-cut specific gravity and boiling point data, are used to determine parameters in the Soreide correlation describing specific gravity-molecular weight relationship. The inter-correlation of assay data is also affected by correlation used between molecular weight, boiling point, and specific gravity. We use a parameter, fTwu, where fTwu=1 honors the Twu correlation exactly, while fTwu= 0 honors a pure-paraffinic correlation between molecular weight and boiling point (independent of specific gravity).
Viscosities of each fraction are correlated against measured data and/or standard-pressure liquid viscosity estimates from the Orrick-Erbar correlation. We use the Lorentz-Bray-Clark (LBC) correlation, where fraction critical volumes are adjusted to give consistency between the LBC estimates for each fraction individually. This approach to determining the critical volumes has proven useful in making the LBC more predictive for overall oil mixture viscosities at reservoir conditions.
An Innovative Approach for Pore Pressure Prediction and Drilling Optimization in an Abnormally Subpressured Basin
Authors: Contreras Oscar , Hareland Geir , Aguilera Roberto 
Published: December 2011

Abstract
Up to now, an indirect generalized method to predict pore pressure under subpressured conditions has not been reported in the literature. In this work, an innovative procedure is presented for estimation of pore pressure and optimization of wells drilled in the abnormally subpressured Deep Basin of the Western Canada Sedimentary Basin (WCSB). The procedure starts with detailed evaluation of 5 wells drilled in a township that covers the study area. Pore Pressure was calculated from Sonic Logs and the Modified D Exponent using Eaton’s Method (Eaton, 1975), which proved to be the most effective approach for abnormal subpressured conditions over a variety of methods tested (Contreras et al., 2011). The optimization procedure was carried out using the Apparent Rock Strength Log (ARSL), which is an effective indicator of formation-drillability and very sensitive to the pore pressure. Next, optimization of individual sections in each well was carried out to determine the optimum types of bits and operational parameters for the lowest cost of drilling.
An artificial intelligence function was implemented to set up the optimum combination of parameters in such a way that the rate of penetration (ROP) (m/h) was increased after a number of simulation runs while controlling the bit wear. Especial attention was focused on tight gas reservoirs for selection of the most suitable parameters that increase the quality of drill cuttings. It was concluded that the rollercone bit IADC 547 with at least 0.73 horsepower in the bit per square inch provides the best quality of cuttings for the Nikanassin Group. This is of paramount importance for increasing accuracy in the quantitative determination of permeability and porosity from cuttings particularly in those tight gas reservoirs where the amount of cores is very limited.
It is concluded that wells in the Deep Basin of the WCSB can be drilled efficiently with 7 bit runs while keeping the cuttings quality, bit wear and well stability at a significantly high average ROP of 13 m/h. Another conclusion is that the normal trend methods from sonic logs are the most effective approach when dealing with an abnormally subpressured basin.