bluuebunny/crossref_metadata_2025_split huggingface dataset:
Strategic Insights From Faltering Exploration Results
Authors: Wilson J. P. , Highton D. G. , Wilson A. , Latham A. , Miles S. , Utz A. , Toulmin S. 
Published: September 2015

Abstract
The health of conventional exploration had been suffering before the oil price crash in 2H 2014; commerciality and value creation both declined dramatically over the past five years. Overall discovered conventional volumes reached exceptional peaks of between 30 and 50 billion boe per year in the years 2009-2012, dominated by two mega-plays: the pre-salt in Brazil and East African gas. The next two years were disappointing in comparison, although average discovery sizes, volumes added per well and success rates held up well. Returns from conventional exploration have been on a downward trend for a decade. The proportion of gas grew, as did the share of volumes found in deepwater. Cost escalation was exacerbated by increasing complexity of both exploration and development. A growing emphasis on frontier deepwater plays resulted in several country-opening oil discoveries. However, these finds fell short of the giant size required to anchor a deepwater development in countries like Sierra Leone, Cote d'Ivoire and French Guiana. In the first half of the past decade, 70-80% of oil volumes are deemed commercial, but the proportion drops to 30-60% in the second half. A shift back towards mature offshore basins is underway and will accelerate in the near term. As the top explorers struggled to replace resources and create value from conventional exploration, many turned to exploration of unconventional resources. Volume additions were undoubtedly strong for most companies, but to outperform by value creation from exploration in resource plays in North America, companies must be first, fast and focused. These trends may hold lessons for those wishing to avoid the short-termism of the current environment. Companies with an appetite for counter-cyclical moves could capture long-term, low-cost resource opportunities, establishing a strong prospect pipeline and building a flexible portfolio that plays to their strengths.
Experimental Investigation of Three-Phase Low Liquid Loading Flow
Authors: Karami Hamidreza , Torres Carlos F. , Pereyra Eduardo , Sarica Cem 
Published: September 2015

Abstract
An experimental study is conducted using a 6-in ID facility to investigate characteristics of three-phase stratified wavy flow in horizontal pipelines. The experiments are conducted under low liquid loading condition, which is very commonly observed in wet gas pipelines. The analyzed flow characteristics include wave pattern, liquid holdup, water holdup, pressure gradient, and wetted wall fraction.
The experimental range covers superficial gas velocity, νSg, values of 8-23 m/s, superficial liquid velocity, νSL, values of 1-2 cm/s, and inlet liquid stream water cut values of 0-100%. Differential pressure transmitters, a quick closing valve and pigging system, and a high speed camera are used to acquire the data. The trends of the data with respect to input parameters are investigated. The performances of commonly used models are compared to liquid holdup, pressure gradient and water holdup experimental results.
The observed wave patterns include stratified smooth and stratified wavy with 2-D waves, 3-D waves, roll waves, and atomization flow. The transitions between the flow patterns vary as a function of water cut. The trends of pressure gradient, liquid holdup, and water holdup with respect to vSg, vSL, and water cut are observed and interpretations based on physics are provided. The predictions of a transient multiphase simulation software, TUFFP Unified Model v. 2012, Beggs and Brill (1973), Taitel and Dukler (1976), and Xiao et al. (1990) are compared to the acquired experimental data. The results from transient multiphase simulation software, Taitel and Dukler (1976) and Xiao et al. (1990) are in good agreement with experimental liquid holdup and pressure gradient data. But the three-phase water holdup trends are not predicted well. The complicated nature of liquid-liquid interactions in three-phase low liquid loading flow causes higher uncertainties in predictions.
The number of experimental three-phase data, especially with larger pipe diameters, is very limited. This paper provides with comprehensive data for three-phase stratified flow for a 6-in ID pipe. In addition, the prediction performance of the commonly used predictive tools in the industry is provided.
The Use of a pH-Triggered Polymer Gelant to Seal Cement Fractures in Wells
Authors: Ho Jostine Fei , Patterson James W. , Tavassoli Shayan , Shafiei Mohammadreza , Balhoff Matthew T. , Huh Chun , Bommer Paul M. , Bryant Steven L. 
Published: September 2015

Abstract
The potential leakage of hydrocarbon fluids or CO2 out of subsurface formations through wells with fractured cement or debonded microannuli is a primary concern in oil and gas production and CO2 storage. The presence of fractures in a cement annulus with apertures on the order of 10–300 microns can pose a significant leakage danger with effective permeability in the range of 0.1–1 mD. Leakage pathways with small apertures are often difficult for conventional oilfield cement to repair, thus a low-viscosity sealant that can be placed into these fractures easily while providing a long-term robust seal is desired. The development of a novel application using pH-triggered polymeric sealants could potentially be the solution to plugging these fractures.
The application is based on the transport and reaction of a low-pH poly(acrylic acid) polymer through fractures in strongly alkaline cement. pH-sensitive microgels viscosify upon neutralization with cement to become highly swollen gels with substantial yield stress that can block fluid flow. Experiments in a cement fracture determined the effects of the viscosification and gel deposition via real-time visual observation and measurements of pressure gradient and effluent pH. While the pH-triggered gelling mechanism and rheology measurements of the polymer gel show promising results, the polymer solution undergoes a reaction caused by the release of calcium cation from cement that collapses the polymer network (syneresis). It produces an undesirable calcium-precipitation byproduct that is detrimental to the strength and stability of the gel in place. As a result, gel-sealed leakage pathways that subjected to various degrees of syneresis often failed to hold back pressures.
Multiple chemicals were tested for pre-treatment of cement cores to remove calcium from the cement surface zone to inhibit syneresis during polymer placement. A chelating agent, sodium triphosphate (Na5P3O10), was found to successfully eliminate syneresis without compromising the injectivity of polymer solution during placement. Polymer gel strength is determined by recording the maximum holdback pressure gradients during liquid breakthrough tests after various periods of pre-treatment and polymer shut-in time. Cores pre-treated with Na5P3O10 successfully held up to an average of 80 psi/ft, which is significantly greater than the range of pressure gradients expected in CO2 storage applications. The use of such inexpensive, pH-triggered poly-acrylic acid polymer allows to seal leakage pathways effectively under high pH conditions.
The Role of Induced Un-propped (IU) Fractures in Unconventional Oil and Gas Wells
Authors: Sharma M. M. , Manchanda R. 
Published: September 2015

Abstract
The term induced un-propped (IU) fractures refers to fractures created around the main propped fracture which are too small to accommodate any proppant. These could include natural fractures, and micro-fractures induced along bedding planes or along other planes of weakness. Based on production data, diagnostic methods and field observations it is becoming increasingly clear that induced un-propped fractures created during the hydraulic operation play a critical role in determining the success of fracture treatments.
In this paper five independent pieces of evidence are presented to prove the existence of induced un-propped fractures in most wells under downhole conditions and to demonstrate their importance in production. These include: micro-seismic data, production history matching, tracer data, pressure communication between wells and finally calculations on the fate of the injected fracturing fluids. Examples are provided to clearly demonstrate how this information indicates the presence of IU fractures.
Once the existence of these fractures has been demonstrated simulations are conducted to show what role these induced un-propped fractures play during fracturing and during short-term and long-term production. It is shown that shale properties and the rheology and rate of injection of fracturing fluids plays an important role in the spatial extent and width of IU fractures. In some shales these fractures play a dominant role while in others they may be less important.
Finally recommendations are made for fracture design to account for the presence of these IU fractures. These recommendations have a large impact on important decisions such as well spacing, fracture spacing, fluid rheology, proppant loading, proppant size and other fracture design considerations. In many instances these recommendations would have been quite different had the presence of IU fractures not been recognized.
A Commercial Evaluation of Refracturing Horizontal Shale Wells
Authors: Indras P. , Blankenship C. 
Published: September 2015

Abstract
Low commodity prices and high costs associated with drilling and completing multistage horizontal shale wells have forced the hand of many US independent E&Ps. Firms are curbing new drilling activity in shale plays and instead are focusing on improving project efficiencies and controlling cash flow. Refracturing programmes are gaining momentum as it costs less to restimulate a producing wells versus drilling an entirely new well.
Despite the bullish view some players have about refracturing, uncertainty remains surrounding the well selection process and the long-term commercial success of refracs. This paper seeks to address this uncertainty by assessing the economic performance of refracturing programmes in three well-developed shale plays - the Bakken, Barnett and Haynesville.
Sensitivity analysis shows that refractured wells, in the Bakken and Haynesville in particular, can generate higher Net Present Value (NPV) than drilling a new well. Refractured horizontal wells in the Barnett, in contrast, show evidence of reduced recoveries and in some cases even value erosion.
Our analysis of historically refractured wells in the Bakken, Barnett, and Haynesville also leads us to believe that the variation in outcomes is too wide for refracturing to be adopted on a large scale today. While some restimulation events indeed have a profitability index (P/I ratio) larger than a new well, others (even in the same play) generate very poor economics. We believe that technology will play a key role in making this asset management approach more common, particularly in decreasing the number of failed restimulation attempts.
Extending Openhole Gravel Packing Capability - Initial Applications of Alternate Path Openhole Shunt Packers to Provide Upfront Zonal Isolation
Authors: Barry M.D. , Hecker M.T. , Arnold S.P. , Barrilleaux S.J. , Sweeney C.M. , Siegman M.J. 
Published: September 2015

Abstract
Openhole gravel pack (OHGP) completions are often selected as the preferred completion technique to provide long life, high capacity, low skin completions. One drawback to OHGPs, however, is the inability to isolate undesirable water or gas within the completion interval whether it is identified during the initial completion or during any point in the production lifecycle of the well. With the recent introduction of a broad suite of Alternate Path® Technology (APT) tools, the added functionality of true openhole zonal isolation can now be combined with the reliability of gravel packing to deliver unparalleled, long-term completion capabilities.
With the advancement of the new openhole shunt packer with APT, wells have been successfully completed to provide capability for future isolation depending on production results of the well. The shunt packer can be run through 9⅝-in casing, set before gravel packing begins, and form a seal against the borehole to provide annular isolation in either round or oval hole sizes up to 10¾-in. These openhole packers have been recently combined with shunted blank joints to provide upfront isolation of unwanted water or gas found while drilling the completion interval to increase well production rate and/or estimated ultimate recovery (EUR).
This paper will describe the first installations of the equipment which combined internally shunted sand screens, openhole shunt packers, and shunted blank pipe to fully isolate water and gas sands within a completion interval while enabling a full gravel pack across the remaining completion.
Managing The Production Lifecycle: A Framework For Scalable Digital Oilfield Implementations
Authors: Gyara Sunitha , Purwar Suryansh , Bravo Cesar , Sarah Queen 
Published: September 2015

Abstract
This paper describes the expanded value of the digital oilfield (DOF) that is made possible by a flexible IT architecture. The architecture is designed for smarter E&P solutions and can cater to an ever-growing appetite for quick, efficient, and proven solutions to diverse productions and operations industry challenges throughout the production lifecycle.
Investments made in early DOF projects have shown an individualistic flavor with unique architecture, approach, tools, standards, and practices without due consideration for scalability and extensibility. Such customized solutions slow down the adoption of good features from one project to other. Typical examples include customized workflows, a lack of open and service-oriented architecture, and a non-standards-based database or application interface. Partly, this could arise because of lack of experienced and skilled resources, gaps in technology, or the absence of any direct or related analogues to the specific problems of the project.
The following IT architectural components are necessary to enable the flexibility that modern DOF projects need to drive returns: A comprehensive production data-management layerAn engineering modeling suiteA petro-technical workflow automation engineAn analytics library and engineAn advanced visualization and collaboration environment
The success of the flexible IT architecture hinges on proper definition, documentation, optimization, and standardization of business processes for all DOF workflows. This ensures the quality and efficiency of repeatable tasks across applications and domains. For this reason, a services-led architecture is critical.
This paper presents a framework for how DOF solutions should be implemented to enable scalability and maximum impact on business profitability. The standardization proposed reduces non-value-adding time during a DOF implementation and improves the companies' long-term ability to make smarter and faster decisions.
Overcoming a Cementing Failure: Sequenced Fracturing Technique for Remedial Application
Authors: Rainbolt Michael F. , Zakharchenko Sergey , Zheng Wei , Oussoltsev Dmitri , Dunaeva Anna , Clark Brian D. 
Published: September 2015

Abstract
The Cottage Grove formation is an active U.S. mid-continent play where cemented horizontal wells are traditionally stimulated by fracturing several perforation clusters simultaneously using limited entry “perf and plug” or other multi-stage completion solutions. Leaving sections of the lateral unstimulated when fracturing over a large interval can be even more severe in un-cemented completions, where the limited entry technique cannot be relied on to distribute the flow of stimulation fluids in the reservoir. Prior to the introduction of the sequenced fracturing technique, there was no solution to reliably stimulate a large un-cemented or openhole sections. This lead to potential losses of EUR in those wells where for some unplanned event, a section of the wellbore cannot be cemented or isolated with plugs. Recently, a well was drilled and unforeseen issues resulted in 3,300 feet of casing with a completely un-cemented annulus. A remedial cement job was not a feasible option and was quickly dismissed. It was decided to use a new sequenced fracturing technique to complete the stimulation without compromising EUR. This technique uses degradable fibers and multi-sized particles as a composite pill to temporarily plug the fractures and divert stimulation slurry to other regions along the wellbore. In this instance, 20 fracturing stages separated by 12 composite pills and 9 bridge plugs were pumped in sequence to optimize the number of fractures along the wellbore and maximize production.
A production and radioactive tracer log run after the operation revealed that the composite pill successfully diverted the treatment fluids from areas previously fractured to previously unstimulated portions of the lateral. As a result, the entire lateral which had been left without cement was ultimately evenly stimulated. This was confirmed by a production log which showed a constant increase in oil and gas production compared to reference wells. Two hundred and six days after the well has been put on production, the well productivity has been more than 30% higher than any offset well.
The design, execution and job evaluation of the treatments are detailed in this paper, and highlight the keys to the successful treatment which turned a well initially thought to be a failure into a technical and economic success.
Practical Considerations for Production Forecasting in Unconventional Reservoir Systems — Processing of Large Group of Wells Using Production Diagnostics and Model-Based Analysis
Authors: Collins P. W. , Ilk D. 
Published: September 2015

Abstract
Production forecasting in unconventional reservoir systems is not an easy task and should not be soley accomplished using empirical decline curve analysis. Advanced analytical and numerical models have facilitated the analysis of unconventional systems; however, it is almost always impractical to analyze and forecast hundreds of wells using these techniques. The focus of this work is to demonstrate a practical and timely methodology using model based production analysis as the foundation for the analysis and forecasting of each producing well in a particular area/field in an unconventional reservoir. The methodology is founded on a thorough diagnostic assessment of all available data, thorough production analysis of key wells, and extension to the remaining wells using key information from the diagnostic analysis.
The methodology includes three main components: production diagnostics, model-based analysis for representative wells, and production forecasting. Production diagnostics is performed on a single well basis to identify flow regimes and performance metrics of each well, and performed on a multi-well basis to compare performance and identify characteristic behavior which can lead to well groupings and the selection of representative wells for analysis. Representative well(s) from each group are analyzed using model-based analysis incorporating non-linear behaviors associated with the production performance. A systematic analysis procedure is followed to account for the uncertainty on well/reservoir parameters affecting production behavior by utilizing an experimental design methodology. Multiple history matches are obtained accounting for uncertainties such as drainage area, permeability, etc.
Following model-based analysis, production forecasts are developed for the corresponding history matches. Based on either a statistical distribution of EUR values or a deterministic approach, characteristic low/mid/high time-rate profiles can be derived. These profiles are extended to other wells via scaling factors to determine EUR values. Coming full circle, the scaling factors are then compared to well/reservoir data using maps and cross plots of performance metrics obtained from diagnostics to aid in the performance based analysis of the group.
Determining Relative Permeability In Shales By Including The Effects Of Pore Structure On Unsaturated Diffusion And Advection
Authors: Daigle Hugh , Ezidiegwu Sandra , Turner Raymond 
Published: September 2015

Abstract
Existing models for shale permeability couple advection and diffusion but do not include the effects of fluid saturations on the permeability. Using a combination of critical path analysis, effective medium theory, and percolation theory, we modeled shale relative permeability by considering the effects of pore structure on unsaturated advection and diffusion. Relevant percolation properties were determined from N2 adsorption-desorption measurements. We considered samples of Green River Shale, Woodford Shale, and Cameo Coal, and isolated kerogens from the Green River and Woodford. We considered gas to be the wetting phase in the kerogens and coal and the nonwetting phase in the bulk shales. We found that the nonwetting phase relative permeability scales linearly with the nonwetting phase saturation, while the wetting phase relative permeability exhibits a highly nonlinear relationship with wetting phase saturation due to the large pore space fractal dimensions (&gt;2.68) of the shales. Based on our model, we predict that water production from the shales is expected to be minor until the gas phase reaches its residual saturation, and that the rate of gas transport out of the kerogen and into the shale matrix should decrease rapidly following the onset of production. This may explain in part why shale gas wells typically produce little formation water and exhibit rapid production decline rates.