bluuebunny/crossref_metadata_2025_split huggingface dataset:
Methods for Enhancing Far-field Complexity in Fracturing Operations
Authors: East Loyd , Soliman M. Y. , Augustine Jody 
Published: February 2011

Abstract
For decades the oil industry has struggled to overcome near-wellbore fracture complexity during fracturing treatments, particularly in low-permeability, naturally fractured hard-rock reservoirs. A number of techniques have been created to diagnose and remediate these conditions to enable extension of created fractures and successful placement of proppant deep in the reservoir. Microseismic fracture-mapping (MSFM) technology has revealed the creation of far-field complex fracture networks in hard-rock reservoirs during fracture extension. This revelation offers the opportunity to hydraulically connect to a much larger volume of rock, provided appropriate treatment techniques are applied to ensure the fracture network is adequately connected to the main fracture. Additionally, techniques have been developed and can be applied during the fracture treatments to facilitate and enhance the fracture-network creation. Net fracture-extension pressure analysis combined with real-time MSFM allows for identifying the degree of fracturing-network creation and provides a decision-making tool for engineers to modify treatment schedules or apply complexity-enhancing methods on-the-fly based on desired treatment objectives and rock responses to the fracture treatment.
This new approach to fracture stimulation requires a new focus on rock mechanics that includes defining the brittleness of the rock matrix, determining the existence and magnitude of the principal-stress anisotropy, designing the optimum spacing between fractures, and defining the optimum fracture-treatment parameters. Once the completion design is implemented, the designed treatment parameters can be adjusted real-time to meet the objectives of the completion based on actual rock responses to the treatment. These rock responses are measured in real-time using net fracture-extension pressure and MSFM diagnostics. Adjustments made to the fracture treatment are varied and include treatment-rate adjustments, proppant concentration, proppant- slug placement, reservoir-diversion treatments, viscous fluid spacers, acid spacers, and incremental stop-start pumping schedules. The proppant-concentration adjustments are enabled for immediate downhole changes through a unique coiled-tubing (CT) fracturing process that incorporates liquid-sand concentrate slurries.
Examples of actual completion designs of these applications are discussed.
Sensitivity of a High-Resolution Fluid-Density Sensor in Multiphase Flow
Authors: Gao Li , van Zuilekom Tony , Pelletier Mickey , Proett Mark , Eyuboglu Sami , Engelman Bob , Elshahawi Hani , Hows Melton 
Published: February 2011

Abstract
An important objective of wireline formation testing is the accurate determination of in-situ fluid properties, including density. However, sensors are frequently subjected to multiphase flow when sampling, which can lead to inaccurate determination of the fluid properties and ambiguity in sample contamination analysis. In this paper, we study the behavior of multiphase flow using a density sensor and the implications for the determination of in-situ fluid properties and sample contamination, together with other downhole sensors.
A vibrating-tube density sensor operates under the physical premise that its resonance frequency is directly related to the density of fluid within the tube. In reality, however, because of its high sensitivity, the sensor response is influenced by multiple factors, including sensor temperature, pressure, and specific mechanical design configuration. A theoretical study of the physics of a vibrating tube density sensor was performed using a first principle-based approach to optimize sensor characterization and accuracy. By considering all forces acting on the sensor under downhole conditions, a comprehensive theoretical model was established for the vibrating density sensor. This theoretical model is validated using experimental measurements in which we contrast theoretically predicted sensor responses with laboratory-measured responses. We compare these results with log examples using downhole fluid sample results and densities. This paper includes the conclusions derived about the accuracy of measuring fluid densities with this new sensor and a comparison of this measurement with traditional data sources.
Synthesis and Properties of Petroleum Sulfonates for Weak Alkali ASP/Alkali-free SP Combination Flooding
Authors: Youyi Zhu , Qingfeng Hou , Hong Yuan , Zhe Wang , Jie Wu 
Published: February 2011

Abstract
Field tests of ASP chemical combination flooding show that chemical combination flooding can greatly increase oil recovery for high water cut oilfields in China. The major problem in ASP flooding technique is that in the strong alkali ASP system, scaling and emulsification bring problems in lifting and produced liquid treatment. In order to avoid the side effect caused by using strong alkali, the development tendency of chemical combination flooding changes from strong alkali ASP flooding to weak alkali ASP flooding and to alkali-free SP combination flooding. The key problem in the weak alkali ASP flooding/SP flooding technique is to develop the surfactant with high interfacial performance, good oil displacement efficiency and lower cost. In this paper, the petroleum sulfonate was synthesized by using Ketone-benzol deep-dewaxing oil fraction as feedstock which with high aromatic content, screening the oil fractions by control average molecular weight of feedstock. The High viscosity stocks were sulfonated using short column falling film reactor. The active content of the petroleum sulfonates synthesized are higher than 38% by direct sulfonating process, it did not require further purification, and thus the synthetic process was improved and the cost was decreased. IFT property of the petroleum sulfonates synthesized showed that ultralow interfacial tension (10−3mN/m) can be reached for Daqing oil/formation water (weak alkali ASP system) and for Jilin oil/formation water (alkali-free SP system). Laboratory core oil-displacement of ASP/SP combination flooding showed that the oil displacement efficiencies of ASP/SP flooding with these surfactants can reach 62-65%(OOIP) which was about 20% and 18% respectively higher than that of the conventional water flooding.
Horizontal Wells with Multi-Stage Fracs Provide Better Economics for Many Lower Permeability Reservoirs
Authors: McDaniel B. W. 
Published: February 2011

Abstract
During the past 5+ years, North America operators have increasingly turned to horizontal completions in low permeability oil and gas reservoirs to maximize their Return on Investment (ROI). As hydrocarbon prices suffered a freefall in late 2008 to mid-2009, this further forced operators to continually evaluate both cost and effectiveness of various completion and stimulation options. In April 2008 the Baker Hughes U.S. rig count for vertical drilling was twice the horizontal rig count, but after the price collapse we soon had more horizontal rigs running than vertical ones, with the June 2010 ratio being ∼1.7:1 while only four years ago the U.S. had 2.5 vertical rigs for every horizontal rig.
Globally, the trend toward horizontal drilling of low permeability oil and gas reservoirs is slowly increasing, with some of the lower permeability onshore and offshore fields also following this trend. As operators see many of their current horizontal completions in moderate to low permeability reservoirs reach their economic limit in only a few years, they often would like to use hydraulic fracturing. However, they are realizing the frac limitations imposed by openhole completion methods and even for highly perforated cemented laterals. Only a few viable options currently exist for effectively placing individual hydraulic fractures at (and ONLY at) preselected locations along the completed lateral section. Unfortunately, often the existing completions limit the fracturing rates that can be achieved.
The primary focus of the North America model for horizontal well economic success is completions that enhance the ability toachieve both adequate injection rates and effective isolation of hydraulic fracturing stimulation stages. In some fields, a secondary goal is to drain significantly more reservoir per well by using radical lateral lengths and reduce the number of wells needed. Onshore this concept makes each well much more environmentally friendly, and offshore the economic value is even more obvious.
This paper will provide a high-points review of the shale formation completion model. With this model it is critical to select the multi-stage fracturing implementation to be used before the lateral completion method can be chosen. Many current methods require that the installed lateral completion contain specific components that are a part of the stimulation isolation method itself. Also reviewed are a few areas that could further advance the present methodology and offer suggestions for where the industry can consider non-shale applications to further proliferate this methodology outside North America.
Permanent Abandonment of a North Sea Well Using Unconsolidated Well Plugging Material
Authors: Saasen Arild , Wold Sturla , Ribesen Bjørn Thore , Tran Tu Nhat , Huse Arve , Rygg Vidar , Grannes Ingvar , Svindland Alf 
Published: February 2011

Abstract
The traditional Plug and Abandonment (P&A) method of exploration wells in the North Sea is to set a series of cement plugs to isolate the pressurised zones from each other and from surface. This paper describes a North Sea P&A field case. In this case an alternative method with a Bingham-plastic unconsolidated plugging material with high solids concentrations was used. This alternative method addresses well integrity issues like those caused by shrinking of cement or gas migration during setting, fracturing after setting, or long term degradation by exposure to temperature and chemical substances in the well.
The gas tight Well Barrier Element (WBE) described here does not set up after placement and does not shrink. Furthermore it cannot fracture even when shear forces exceed its strength. When this happens the material floats and shear forces are reduced below yield strength causing the plug to reshape. Since this is a purely mechanical process the transition between solid and fluid phase is repeatedly reversible forever.
The plug is thermo-dynamically stable since its sealing property is decided by the solids particle size distribution and bound water only. The closely packed particles and absence of free water means that the entire column is kept homogenous and no internal re-distribution of particles may occur. Hence, the permanent gas-tight barrier will prevent influx through the well bore forever.
In the field case a successful implementation of the technology was obtained. The field case shows how the fast and efficient placement of the plug contributes to overall cost reduction. The paper explains how the well barrier element complies with governmental permanent P&A requirements and the operational procedures are also presented in some detail.
Innovative Metallurgical Technology Delivers First Sulfide Stress Cracking Resistant Intervention Riser System with Quick Running, Rugged Connections
Authors: Jellison Michael , Hehn Lucien , Moreira Jose Roberto , Joia Carlos J.B.M. , Wyble Kevin , Christen Brian 
Published: February 2011

Abstract
Petrobras has been using a 6-5/8 in. drillpipe based riser system for intervention work offshore Brazil for several years. The primary advantage of the drillpipe based system relates to the rotary shoulder connections (RSC). RSC’s make-up and break-out quickly, are rugged and are superior at resisting galling and other handling damage compared to OCTG connections that are often used for riser applications.
Petrobras has been prevented from expanding their use of the intervention risers in sour gas areas because there were no fully Sulfide Stress Cracking (SSC) resistant tubulars with RSC’s. The intervention riser configuration consists of upset to grade tubes friction welded to tool joints that are typically constructed from forgings. Sour service drillpipe has been available for some time. This pipe is built with SSC resistant upset tubes and tool joints. The friction welds joining the upset tubes and tool joints were not resistant to SSC. This is acceptable for drilling since the weld is not the high stress area of the assembly and the drilling environment can be controlled through the drilling fluid properties and additives. Petrobras’ critical sour riser applications could entail direct and prolonged exposure to H2S gas. Consequently, a fully SSC resistant system including the friction weld was required.
This paper presents the successful development and qualification of SSC resistant friction welds for intervention riser systems. It describes the engineering and manufacturing philosophy employed, laboratory testing procedures and results and Petrobras’ applications for the new risers. Since NACE MR-0175 does not address friction welds the engineering team developed unique and innovative criteria and testing procedures for the new weld technology. A new patent pending four point bending test procedure and fixture were develop that employed unpolished samples that closely represent the finished product surface finish (NACE testing typically uses polished specimens).
Pressure Transient Analysis and Simulation of Nonconventional Wells
Authors: Iktissanov V.A. 
Published: February 2011

Abstract
Nowadays nonconventional wells (horizontal, multilateral, Rad Tech and others) are being extensively drilled throughout the world for the development of low-profit fields. Construction of these wells enables to reduce filtration resistivity resulting in productivity index increase and costs reduction.
To select the optimal well design with regard to reservoir characteristics, effective well operation and determination of filtration characteristics one should possess calculation methods for steady and unsteady liquid flow in reservoir.
Few related papers have been published so far. However analytical methods for steady flowing are suitable for homogeneous beds with simple geometry and equal length laterals. Available approaches for description of pressure build up allow to account for various lateral trajectories but FEA or semi-analytical decisions methods are too labor-intensive for practical application.
Therefore simple methods of productivity index determination and pressure transient test interpretation are suggested for nonconventional wells. These methods are suitable for low thickness beds. The basis of these methods is the superposition of filtration resistivity for two plane problems. Trajectory of laterals is simulated as a number of closely spaced vertical wells or nodes. The suggested method allows determining the field of application and regularities for nonconventional wells.
Dimensionless fluid-movement profile calculated from steady fluid flow and a superposition method for pressure builds up in the nodes are used for determination of pressure build up. For description of build up in a node we recommend a diffusion equation in Laplace space and Stephest numerical algorithm. The problem is solved for porous and doublt porosity reservoirs.
Numerical calculations show that cross-flows occur after the horizontal or multilateral well shut-down. Pressure derivative maximum testifies to low effective length of the borehole or positive skin-effect. Knowledge of effective intervals length is critical to pressure curve interpretation.
Production Logging in Highly Deviated and Horizontal Wells: Moving From Qualitative to Quantitative Answers
Authors: Gysen Alain , Gysen Michel , Zett Adrian , Webster Mike , Yusti German 
Published: February 2011

Abstract
A variety of technologies have been used to address the challenges faced by Production Logging (PL) in high deviation and horizontal wells.
Different configurations of array sensors have been deployed in these environments, to address well work objectives. There are situations where it is hard to differentiate between qualitative and quantitative answers. The question is how quantitative is high angle and horizontal PL data.
Multiple datasets were studied and increased value can be added to array raw data by improvements to processing and interpretation. There is a need to differentiate between data acquisition and data processing and interpretation for high angle and horizontal PL.
This paper describes a probabilistic approach developed to combine sensor responses into a quantitative solution. Individual sensors from a multiple array production suite can be used in combination with centralised (conventional) sensors to address reservoir conditions and well access challenges. Difficult well completion and rig height limitation increase the complexity level in such environments. This probabilistic approach is applied in a complex North Sea example to gain greater reservoir understanding with a rapid turnaround.
Sourceless Porosity Estimation in Gas Reservoirs Using Integrated Acoustic and NMR Logs
Authors: Lan Chun , Chen Songhua , Mendez Freddy , Sy Rex 
Published: February 2011

Abstract
Due to environmental concerns, the use of radioactive chemical sources is discouraged. This presents great challenges for conventional practices. Source-free logging tools, such as Nuclear Magnetic Resonance (NMR) and acoustic tools, have also been used for porosity determination. However, sometimes uncertainties in lithology, mineralogy, and/or fluid properties can result in unacceptably large error bars in porosity by either NMR or acoustic logging alone. Integrating acoustic and NMR measurements for gas-zone porosity estimation has been reported in relatively clean sandstones. The existing method in literature has not been extended to shaly sandstone reservoirs or carbonate formations where clay is also present. We developed a new, practical sourceless porosity-estimation method which uses NMR log to calibrate the acoustic porosity model and which corrects shale effect on acoustic porosity.
To apply this method, both clean and shaly water-bearing intervals are selected for calibrating acoustic model parameters. By applying the calibrated model, dry matrix slowness on each depth in the gas-bearing interval can be obtained. Porosity can then be determined by introducing the computed dry matrix slowness to Raymer-Hunt-Gardner transform for the gas-bearing interval.
This method has been successfully tested on a number of wireline and LWD logs. In this paper are two case histories; one case study involves a shaly sand reservoir, and the other, a low-porosity carbonate reservoir. For both cases, the sourceless porosity is cross-validated with other approaches for both the water-bearing and gas-bearing sections.
An Alternative Mechanistic Model for Permeability Changes of Coalbeds During Primary Recovery of Methane
Authors: Mazumder Saikat , Farajzadeh Rouhi 
Published: February 2011

Abstract
Volumetric shrinkage due to methane desorption from the coal matrix has significant influence on the stress regime and fracture permeability in coal. Permeability changes (due to primamry depletion) up to two orders of magnitude have been reported from the Fairway region in the San Juan Basin. Several analytical models have been developed to predict changes in fracture permeability in coal as a function of stress and sorption induced coal swelling/shrinkage.
Coal can be considered as a highly crosslinked macromolecular network structure, where aromatic clusters of graphite like complexes are connected by aliphatic chains. All sorption processes in coal are characterized by relaxational mechanisms of such crosslinked complexes. Any relaxational mechanism is indicative of swelling related stresses in coal. Variations in the effective horizontal stresses under uniaxial strain conditions are effected as a function of the reservoir pressure reduction during primary drawdown, which includes a cleat compression term and a matrix shrinkage/swelling term that have opposite effects on fracture permeability.
The matrix shrinkage/swelling term have been revisited a theory proposed to explain the coupling of swelling stress to porosity change in coal as a function of the change in diffusion coefficient, the Langmuir constants, cleat compressibility and material properties.
30 Years of Successful High-Pressure Air Injection: Performance Evaluation of Buffalo Field, South Dakota
Authors: Kumar V. K. , Gutiérrez D. , Thies B. P. , Cantrell C. 
Published: February 2011

Abstract
The Buffalo Field enhanced oil recovery project is the oldest, still active, air injection project in the United States. The combination of depth (8,500 ft), high pressure (4,200 psi), light oil (32 °API), high reservoir temperature (215 °F) and low permeability (1 to 20 md) carbonate formation makes this a unique air injection project, covering a large area (33,160 acres). The project's longevity attests to both its technical & economic success.
Laboratory studies (combustion tube, miscibility pressure and swelling tests for various CO2-N2 mixtures) and feasibility studies including air injectivity testing were completed in mid-1977. The result of the pilot test was promising and the 2,240-acre Buffalo Red River Unit (BRRU) was formed in November 1978. As production response continued to be encouraging, the BRRU was expanded to 7,680 acres in May 1981. Two other EOR units, South Buffalo Red River Unit (20,800 acres) and West Buffalo Red River Unit (4,680 acres) were formed adjacent to BRRU, in 1983 and 1987 respectively.
The three units currently have a total of 59 producers and 20 injectors. Oil production in all units has shown significant increase over its historical decline under continued primary. Peak production reached 3,030 BOPD in June 1991. Current production is 1,500 BOPD and injection is 30,500 Mcfd. Cumulative air injection through December 2009 is 262 Bcf and the incremental production due to air injection is about 18.1 Million barrels resulting in cumulative air utility of 14.5 Mcf/incremental barrel.
This paper focuses on the technical aspects of the Buffalo EOR project, reviewing laboratory studies, production performance (1978 to 2009) and the impact of short radius horizontal drilling. It also includes estimates of the EOR barrels produced, how air utility and air retention have changed over time, and estimates of the burned volume in each of the units.