bluuebunny/crossref_metadata_2025_split huggingface dataset:
A Comparison of Core and Well Log Data to Evaluate Porosity, TOC, and Hydrocarbon Volume in the Eagle Ford Shale
Authors: Quirein John , Murphy Eric , Praznik Greg , Witkowsky Jim , Shannon Scott , Buller Dan 
Published: October 2012

Abstract
The Eagle Ford Shale hydrocarbon-fluid properties depend on the source rock maturity and, within the formation, occur in varying degrees of gas, gas condensate, and oil. Using conventional logs and pyrolysis data, several log-core regressions, such as delta log R, density, and uranium, can be derived to predict total organic carbon (TOC). The TOC can be used in conjunction with geochemical elemental measurements for a more accurate assessment of the formation kerogen and mineralogy, as well as hydrocarbon volumes. Nuclear magnetic resonance (NMR) porosity measures an apparent total porosity in the organic shale plays, measuring only the fluids present and excludes the kerogen. The complex refractive index method (CRIM) in conjunction with the mineralogy log data can be used to compute accurate dielectric porosities, which exclude both kerogen and hydrocarbon. Integrating the core TOC, predicted TOC, mineral analysis, NMR, and dielectric information, a final verification of the kerogen volume, hydrocarbon content, and mineral analysis can be assessed.
This paper will describe the integration of conventional logs, a geochemical log, an NMR log, and dielectric to predict TOC, kerogen volume, and hydrocarbon volume, as well as, total porosity and mineralogy. The data is compared to the actual core data from three Eagle Ford wells, and it will be shown how the proposed approach will eliminate some coring operations. Finally, it will be shown how these interpretation results can be rolled up to make decisions on where to drill the lateral.
Experimental Investigation of Wellhead Twin-Screw Pump for Gas Well Deliquification
Authors: Morrison Gerald L. , Kroupa Ryan , Patil Abhay , Xu Jun , Scott Stuart , Olsen Sven 
Published: October 2012

Abstract
Onshore gas developments are often characterized by drilling, fracturing and production of wells before low-pressure gas gathering systems are in place. As well production declines, liquid loading issues begin to appear. Gas well deliquification (GWD) can be accomplished using compression or in-well artificial lift methods, or both. Wellhead wet-gas compression is desirable in that it does not require well intervention to provide GWD and is especially useful to maintain well production in the interim period before field-wide compression is available. Also, even when field-wide compression is available local wellhead compression is desirable at various locations in a field as high-rate wells are added or for wells located at peripheral locations. The use of a twin-screw pump to provide boost for high Gas Volume Fraction (GVF) multiphase flow was experimentally investigated. Tests were conducted with pressure rises ranging up to 250 psi for GVF's above 90%. Water and air were used as the working fluid. The pumping system is a commercially available 230 gpm twin-screw pump (60 hp) with a design speed of 3600 rpm used in conjunction with a knock out tank used to re-circulate liquid from the pump exit to provide seal flush. The electrical power required to operate the pump, liquid and gas inlet flow rates, pressure rise, and inlet and exit temperatures were recorded. From these data, the volumetric efficiency, pump effectiveness, and mechanical efficiency were calculated. Since there is a fixed clearance between the rotating screws and the pump housing, there is a leakage from the high to low pressure regions of the pump which will reduce the pump's volumetric efficiency. It was found that the volumetric efficiency decreased significantly with decreasing pump speed and decreasing GVF. At full speed the volumetric efficiency was between 70 and 88% at DP=50 psi. Increasing DP to 250 psi decreased these values to 55 and 81% respectively. The mechanical efficiency was relatively constant over the pressure rise range varying from a high of 48% at the lowest inlet pressure and 100% GVF to a low of 14% 14% for both inlet pressures at 100% GVF. Overall, the testing demonstrated the ability of a surface twin-screw pump to provide wet-gas compression and to tolerate 100% gas input, which may results from slugging or periodic flow, for relatively large periods of time.
Extended Finite Element Modeling of Multi-scale Flow in Fractured Shale Gas Reservoirs
Authors: Sheng M. , Li G. , Shah S. N. , Jin X. 
Published: October 2012

Abstract
An economic production scheme for gas shale demands a better understanding of gas flow behavior and a proper reservoir simulator. The complex fracture network and multi-scale flow channel intensify the complexity of gas flow behavior. This paper integrated an improved shale-gas transport model with the extended finite element method (XFEM) to characterize the main flow mechanisms and discrete fracture network. The gas shale was viewed as the dual permeability porous media with discrete fractures. The discrete fractures are not required to be meshed, which can be placed anywhere with given location, length, and orientation. Rock deformation is implicitly coupled with gas flow to reflect stress sensitivity of gas shale. Furthermore, the displacement and matrix pore pressure across fractures are treated as discontinuous by using enrichment approximation functions. The computer coding of proposed model was developed. Terzaghi's problem for dual permeability media was considered to validate the code. The results show that pressure field is disturbed by the discrete fractures obviously, which is compared with regular pressure field obtained from the continuous fracture model. Therefore, it is important to account for discrete fractures for the fractured porous media. One case study of shale gas reservoir was presented to improve the model application. Two patterns of fracture networks were simulated in the rectangular reservoir. It is evident that the orthogonal fracture network is an ideal pattern contrast to the oblique fractures, since the former makes the pore pressure field depleted symmetrically. Furthermore, the stimulated area is the main factor to control the pressure depletion. The results confirm that the presented model and code is capable and flexible to simulate shale gas reservoir with discrete fracture network. This work provides an alternative workflow for parameter designs of hydraulic fracture and production scheme.
Optimized Cased and Perforated Completion Designs Through the Use of API RP-19B Laboratory Testing to Maximize Well Productivity
Authors: Procyk Alexander D. , Burton Robert C. , Atwood David C. , Grove Brenden M. 
Published: October 2012

Abstract
A detailed perforating study was conducted for a high pressure and high temperature (HPHT) reservoir which provided challenging conditions for conventional perforating. To maximize productivity, a series of API RP-19B Section 2 and Section 4 experiments was conducted to optimize perforation conditions. These results were integrated with mud testing and operational considerations to create an overall completion design for the field.
Section 4 tests were performed at static overbalance, static underbalance and dynamic underbalance conditions scaled to field conditions using either mud or base oil as the completion fluid. The core flow efficiency and perforation geometry were evaluated to determine the optimum perforation method to achieve the target skin. The Section 4 apparatus could not achieve absolute field pressure and temperature conditions, therefore to ensure the required perforation geometry could be achieved downhole, Section 2 tests were conducted at the HPHT field conditions of reservoir overburden stress (13,000 psi), reservoir pressure (&gt;11,000 psi) and temperature (&gt;300 F).
The results showed that dynamic underbalance removed significant portions of the perforation crushed zone and resulted in high productivity flow even when perforating in mud. Static underbalance was significantly less effective in removing crushed zone damage and overbalanced perforating in mud yielded poor results. Perforation geometry was radically altered upon going from relatively low stress conditions to full HPHT reservoir conditions when the cores were saturated in a light mineral oil. This change in perforation geometry was not observed when the cores were saturated in water, indicating that the fluid compressibility may have a significant impact on perforation geometry under high stress conditions. These results point to the value of conducting Section 2 and Section 4 experiments early in a project's timeline so that the best completion designs can be pursued and ultimately used in the field to maximize well productivity.
A Petrophysical Model to Estimate Relative and Effective Permeabilities in Hydrocarbon Systems and to Predict Ratios of Water to Hydrocarbon Productivity
Authors: Holmes Michael , Holmes Antony , Holmes Dominic 
Published: October 2012

Abstract
Permeability estimates from petrophysical interpretations rely mostly on relations between porosity and irreducible water saturation, for example using the approach developed by Timur (1968). If core data are available for calibration, it is common that the transform used can be quite reliable. However, relative permeability estimates require quantification of water saturation greater than irreducible saturation.
In a previous publication by the authors (Holmes, et al, 2009), methodology was presented to distinguish rocks at irreducible saturation from those that contain mobile water. The technique involves a modified interpretation of porosity/saturation cross plots to identify levels at irreducible water saturation using a Buckles (1965) relationship. Once this data trend has been identified, water saturation at any given data point can be compared with theoretical irreducible saturation. Values of water saturation above irreducible water saturation indicate the presence of mobile water.
Using a representative relative permeability curve, or a reservoir-specific relative permeability curve, relations can be established between water saturations above irreducible and the accompanying relative permeability, both to hydrocarbons and water. Once this is available, effective permeabilities to each phase can be calculated level-by-level. The procedure involves comparing differences between water saturation and irreducible water saturation with measured relative permeabilities to both wetting and non-wetting phases, expressed as exponential equations. Effective permeabilities are then available as the product of relative permeability and log-estimated permeability. By factoring in mobility ratios of hydrocarbons and water, it is then possible to estimate profiles of water cuts in oil/water systems, or barrels of water per million cubic feet of gas (Bbl/MMCFG) in gas/water systems.
Examples are presented for both oil/water and gas/water systems, showing good correlation with fluid production from well tests.
Using Equipment Simulators for Effective Training, Increasing Competence in Well Services Operations
Authors: Celano Anthony , Kersey George , LeBlanc Aladain , Fiffick William 
Published: October 2012

Abstract
Learning on-the-job has been considered as among the most practical and effective methods to train Engineers and Technical Operations personnel. Lessons learned and best practices can be modeled and taught to less experienced employees. The new learners are provided with the benefit of hands-on operations under supervised conditions where proper behaviors could be modeled and mistakes corrected. But that model of training is changing. Technological advances have resulted in enhanced automation, control and feedback but with greater operational complexities. The modern equipment provides great gains in efficiency and control, but may require a higher degree of skill on the part of the operators and engineers. Unfortunately, as a result of the "Great Crew Changei", fewer competent mentors and trainers remain in the field to pass along those lessons learned and best practices. To compound the training challenges, it is often impractical (or impossible) to allow those learners to "practice" without compromising either operational or job safety concerns.
Fortunately, by leveraging technologies and with some investment in equipment, the "field" can now be brought to classroom. By working with competent instructors, in a controlled environment, many of the benefits of hands-on field experience can be achieved.
This is a case study of how a major oil field services company is employing modern simulation technology to meet (or exceed) technical training and competency requirements. Details about the rationale and the concept of simulation training, learning theory, logistical concerns, development of simulators and results are discussed.
A Case for Oil-Based Fracturing Fluids in Canadian Montney Unconventional Gas Development
Authors: Hlidek Barry T , Meyer Russell K , Yule Keri , Wittenberg Joerg 
Published: October 2012

Abstract
This paper presents a fracturing case study from the Montney gas play in the Western Canadian Sedimentary Basin. There is a long history of debate regarding the use of oil-based fracturing fluids; the debate is centered on the argument that the benefits of oil-base fracturing fluids do not justify the increased cost of supplying and using oil as a base fluid. The economics are substantially different not only because of the cost of fracturing oil itself, but also because of the associated environmental, safety, and disposal costs. From an environmental sustainability point of view, 100% of the frac oil is recovered; the oil is cleaned and recycled at least twice before being sold into the market. In contrast, water used in fracturing—typically surface water—is completely removed from the hydrological cycle: Flowback water is treated as effluent and disposed.
The case study analyzed in this paper demonstrates the benefits of using oil-based fluids over water-based fluids in the Karr region of the Montney play. The Montney in this area is best described as an undersaturated, fine-grained, siliciclastic reservoir. All wells are horizontal and completed using multistage isolation techniques. The characteristics and petrology of the reservoir are examined, along with fracture geometry simulations. Laboratory data is presented to support the use of oil-based systems. Treatment summaries and flowback data are presented. Finally, long-term production data from the field provides a direct comparison between oil- and water-based fracturing fluid treatments, allowing economic analysis of the two options. Beyond improved production profiles, some common misconceptions regarding the environmental and economic impact of oil-based fluids are addressed.
Analysis of Unsteady Responses of Natural Gas Reservoirs via a Universal Natural Gas Type-Curve Formulation
Authors: Ayala H. , Luis F. , Ye Peng 
Published: October 2012

Abstract
Gas decline curve analysis has traditionally relied on the use of liquid (oil) type curves along with the concepts of pseudopressure and pseudo-time and/or empirical curve fitting of rate-time production data using Fetkovich type curves for gas well performance and reserve estimations. In this work, we show that a single-line, universal type curve can instead be derived for the analysis of unsteady state of natural gas wells under boundary dominated flow (BDF). The proposed decline equation is presented in its analytical, closed functional form and is shown to model production from any gas well producing at constant bottomhole pressure under BDF. On the basis of this decline model, a universal type-curve is formulated for type curve matching of natural gas well producing under BDF, for any constant drawdown condition, and regardless of intrinsic reservoir and fluid properties. New-generation analytical procedures for gas well performance analysis are presented, which does not necessitate the calculation of pseudo-pressure or pseudo-time. Explicit OGIP predictions are thus enabled from the proposed universal type curve matching. The importance of conducting unambiguous reserve estimations based on rate-time data and reliably predicting future well performance cannot be overstated. The proposed single-line type curve is demonstrated to do so by successfully matching rate-time production BDF data and reliably estimating fluid in place for a number of numerical simulations and field cases. It is finally shown that the proposed formulation can be alternatively implemented in terms of straight-line analysis of 1/qgscb versus time data plots.
A Procedure for Integrating Geologic Concepts into History Matching
Authors: Lun Lisa , Dunn Paul , Stern Dave , Oyerinde Adedayo , Chorneyko Dave , Stewart Jonathan , Fowler Kenneth , Nollet Sofie 
Published: October 2012

Abstract
This paper describes a history match study carried out on a deep water reservoir with roughly a year of production history, consisting of flowing bottom hole pressure (FBHP) and oil rate measurements. This study demonstrates a procedure that can be used to integrate geologic concepts with the history match process to find a range of geologically realistic reservoir descriptions that are all consistent with production history to date for evaluating uncertainty in predictions. The process has three steps: 1) determine, based on geologic and engineering data, what model inputs will be tested in history matching; 2) develop an experimental design(s) and use it(them) to test the impact of those inputs on reservoir performance; and 3) select models for further history match work or prediction of future performance. Two geologic features were selected for study:
The degree to which the boundaries between stratigraphic elements seal. Analysis of seismic data identified three levels of stratigraphic elements - channel complex sets, channel complexes, and channel complex remnants. Degree of sealing represents the presence of sub-seismic shale drapes at each level. The degree to which faults are sealed, which depends on the net-to-gross ratio and the throw of each fault. The degree to which a given fault seals is uncertain because it depends on the detailed spatial arrangement of sand and shale in the fault zone, which is not measured directly.
The impact of shale drapes was evaluated first. Four shale drape scenarios were chosen to represent a range of behavior including the best match, and seven fault seal scenarios were used to further evaluate the impact of fault seal. Our analysis in this case revealed that the pressure depends on both fault seal and shale drape continuity, with the best matches observed when either faults or stratigraphic boundaries are partially closed and the other geologic feature is open. This allowed selection of seven reservoir descriptions for use in predictions.
Rock Classification in Carbonate Reservoirs Based on Static and Dynamic Petrophysical Properties Estimated from Conventional Well Logs
Authors: Xu Chicheng , Heidari Zoya , Torres-Verdín Carlos 
Published: October 2012

Abstract
Rock typing in carbonate reservoirs is challenging due to high spatial heterogeneity and complex pore structure. In extreme cases, conventional rock typing methods such as Leverett's J-function, Winland's R35, and flow zone indicator are inadequate to capture the heterogeneity and complexity of carbonate petrofacies. Furthermore, these methods are based on core measurements, hence are not applicable to uncored reservoir zones.
This paper introduces a new method for petrophysical rock classification in carbonate reservoirs that honors multiple well logs and emphasizes the signature of mud-filtrate invasion. The method classifies rocks based on both static and dynamic petrophysical properties. An inversion-based algorithm is implemented to simultaneously estimate mineralogy, porosity, and water saturation from well logs. We numerically simulate the process of mud-filtrate invasion in each rock type and quantify the corresponding effects on nuclear and resistivity measurements to derive invasion-induced well-log attributes, which are subsequently integrated into the rock classification. Under favorable conditions, the interpretation method advanced in this paper can distinguish bimodal from uni-modal behavior in saturation-dependent capillary pressure otherwise only possible with special core analysis.
We successfully apply the new method to a mixed clastic-carbonate sequence in the Hugoton gas field, Kansas. Rock types derived with the new method are in good agreement with lithofacies described from core samples. The distribution of permeability and saturation estimated from well-log-derived rock types agrees with routine core measurements, with the corresponding uncertainty significantly reduced when compared to results obtained with conventional porosity-permeability correlations.
Extending the Range of Gas Lift to Long Perforations
Authors: Polasek Darryl , Frost Chandler 
Published: October 2012

Abstract
Problem being addressed: Operators face many challenges when producing deep vertical wells and long horizontal or deviated well bores. Traditional artificial lift methods can prove inefficient or ineffective when applied to this new breed of wells.
Challenges: In wells with long perforated intervals, insufficient velocities below the packer can cause liquid loading. Many traditional artificial lift methods are limited in their ability to address liquid loading issues in these types of wells.
Solution: If gas can be injected below the packer and deep into the perforated zones, gas lift can be an effective means of deliquification. Advances in gas lift system design now provide several options for effectively recovering liquids from completion intervals below the packer. We will discuss a few of these systems, including Annular Bypass Assembly (ABA), Dip Tube, Enhanced Annular Velocity (EAV), Marathon AVE, and Dead String. Each employs unique techniques that allow for gas injection deep into the perforated zone by passing the lift gas through or around the packer. Using the basic principles of gas lift, the injected gas aerates the liquid in the perforated zone, decreasing the hydrostatic density and flowing gradient and improving inflow from the formation. By also increasing velocity in the production string, these gas lift systems allow operators to more efficiently recover fluids and minimize or prevent liquid loading.
Results: Below-packer gas lift systems are being used successfully to economically produce wells in unconventional plays. We will review the design and mechanics of each of the above-mentioned systems, share our experiences working with operators and discuss the selection criteria in choosing a system.