bluuebunny/crossref_metadata_2025_split huggingface dataset:
Casing While Drilling Utilizing Rotary Steerable Technology in the Stag Field-Offshore Australia
Authors: Graves Kyle S. , Herrera Gomez Delimar Cristobal 
Published: June 2014

Abstract
Originally discovered in 1993, the Stag Oil Field, located on the Northwest Shelf of Western Australia, has produced over 58 MMbbls since production began in 19987. The Field is a shallow (680m SS), highly unconsolidated, highly permeable sandstone. Reservoir depletion, unconsolidated rock, water breakthrough and sand production have created conditions where infill drilling campaigns have become increasingly problematic in the Stag field in recent years. Numerous papers have documented the history of the Stag Field's colorful past12-13, 23.
On three recent infill wells the intermediate 12 ¼?? intervals were drilled and cased using Casing while Drilling (CwD) technology using a rotary steerable system. This was used to navigate wellbore congestion, drill designer wellpaths to avoid "incoherencies?? (a seismic attribute that is mappable and correlates with drilling problems5), land the horizontal section and then drill horizontal tangent sections out to the initial reservoir penetration (liner point). The CwD applications progressed from a "new technology?? trial to a stretch reach and performance goal, to finally successfully being used a key enabling technology to drill a well that might otherwise be undrillable due to instability issues.
The directional CwD 12 ¼?? hole intervals were drilled from just below the 13 3/8?? surface casing to the 9 5/8?? casing point, building from 25 degrees inclination to horizontal and holding thereafter. This program (the first applications of this type in Australia) resulted in two consecutive world record runs. The result is that CwD is a viable enabling technology that will be used to drill future Stag infill and should be considered as a viable alternative on other drilling projects.
This paper will discuss the identification of the technology application, planning, implementation, results and lessons learned. This paper will end with a notional conversation regarding CwD becoming a mainstream method.
A New Approach for the Simulation of Fluid Flow in Unconventional Reservoirs through Multiple Permeability Modeling
Authors: Yan Bicheng , Alfi Masoud , Wang Yuhe , Killough John E. 
Published: June 2014

Abstract
Shale reservoirs are characterized by ultra-low permeability, multiple porosity types, and complex fluid storage and flow mechanisms. Consequentially the feasibility of performing simulations using conventional Dual Porosity Models based on Darcy flow has been frequently challenged. Additionally, tracking of water in shale continues to be controversial and mysterious. In organic-rich shale, kerogen is generally dispersed in the inorganic matter. Kerogen is different from any other shale constituents because it tends to be hydrocarbon-wet, abundant in nanopores, fairly porous and capable of adsorbing gas. However, the inorganic matter is usually water wet with low porosity such that capillary pressure becomes the dominant driving mechanism for water flow, especially during hydraulic fracturing operations. This work presents a technique of subdividing shale matrices and capturing different mechanisms including Darcy flow, gas diffusion and desorption, and capillary pressure. The extension of this technique forms a solid and comprehensive basis for a specially-designed simulator for fractured shale reservoirs at the micro-scale.
Through the use of this unique simulator, this paper presents a micro-scale two-phase flow model which covers three continua (organic matter, inorganic matter and natural fractures) and considers the complex dynamics in shale. In the model, TOC is an indispensable parameter to characterize the kerogen in the shale. A unique tool for general multiple porosity systems is used so that several porosity systems can be tied to each other through arbitrary connections. The new model allows us to better understand the complex flow mechanisms and to observe the water transfer behavior between shale matrices and fractures under a microscopic view. Sensitivity analysis studies on the contributions of different flow mechanisms, kerogen properties, water saturation and capillary pressure are also presented.
Geological Attributes from Conventional Well Logs: Relating Rock Types to Depositional Facies in Deepwater Turbidite Reservoirs
Authors: Xu Chicheng , Torres-Verdín Carlos , Steel Ronald J. 
Published: June 2014

Abstract
Grain size and bed thickness are important geological attributes for sedimentary facies analysis and reservoir quality ranking in deepwater turbidite reservoirs. Grain size controls reservoir quality and has causative or correlational effects on most well logs. Additionally, bed thickness affects well logs in various ways because of different vertical logging-tool resolutions. The objective of this paper is to quantitatively classify rock and bed types based on conventional well logs to assist facies interpretation and stratigraphic reservoir modeling.
We model physical properties and well-log responses originating from clastic reservoirs with different grain-size distributions in the context of deepwater turbidite systems. The model accounts for fluid effects introduced by capillary transitions and salty connate water. Petrophysical relationships are examined between grain sizes and pore geometry as inferred from the combined effects of initial connate-water saturation and reservoir capillary pressure. From modeling, we derive several quantitative petrophysical attributes which correlate significantly with grain size. A list of such attributes includes volumetric concentration of shale, total porosity, neutron-density porosity difference, and reservoir quality index (RQI). Rock classification is then performed based on a relevant set of attributes to detect and rank different rock types with specific grain-size distributions. Concomitantly, a quantitative rock classification scheme using three-dimensional Thomas-Stieber diagrams constructed with gamma ray, bulk density, and resistivity logs is used to classify petrophysical zones based on their average bed thicknesses. A dual-attribute rock classification scheme is proposed to better associate rock types with depositional facies.
The above-mentioned rock-classification and bed-typing methods are synthesized and applied to a turbidite field from the Gulf of Mexico. We perform facies analysis based on the vertical succession of rock types (grain sizes) and the inferred variations of bed thickness. The field case demonstrates that these two geologic attributes have great potential in reducing uncertainty and non-uniqueness in the construction of stratigraphic reservoir models. Results indicate that the classified rock types and their petrophysical ranking agree with core data while the interpreted facies fit into the depositional context as inferred from core descriptions and seismic horizons.
A Correlation for the Coefficient of Inertial Resistance for Producing Reservoirs within the Columbus Basin
Authors: Baksh Kirk 
Published: June 2014

Abstract
BP Trinidad and Tobago LLC produces gas from the Columbus Basin located off the east coast of Trinidad. Gas is produced via eleven producing platforms and daily gas production averages 2.3 bscfd. Gas produced is used to supply a domestic market and an LNG scheme. The field portfolio comprises a mix of new to mature producers producing from a deltaic environment which consists of several stacked, good quality sandstone reservoirs. The wells have been primarily designed as big-bore/high-rate completions (equipped with continuous down-hole and surface monitoring) with the aim of delivering gas to market with minimal well count.
Performance data has shown that the non-Darcy rate dependent skin is the biggest contributor to the total skin effect in these high rate wells. Early determination of the non-Darcy flow coefficient "D" enhances the ability to accurately forecast well deliverability; which is critical to both the end users and the business for proper activity planning and capital efficiency. It stands to reason that a proper understanding of same is also advantageous in predicting the performance of new producers.
Predicting the non-Darcy flow coefficient in the absence of well test data requires the value of the coefficient of inertial resistance, β; which is normally determined experimentally. This paper outlines the methodology whereby a correlation for β was developed using non-Darcy flow coefficients obtained via well tests and corrected to sand top; hence making it possible to provide an estimate of the non-Darcy flow coefficient for proposed producers. The predicted performance is then compared against actual performance for a number of cases.
Integrating Completion and Drilling Techniques to Improve & Maximize Production over the Life of the Well
Authors: Scott Gregory , Smith* Lee M. , Johnston Adam D. 
Published: June 2014

Summary
This paper describes application of an integrated approach that combines drilling and completion techniques in a new use of reaming tools currently used for reaming-while-drilling (RWD) operations, in a way that minimizes the need for SOP of using a dedicated reamer run. The RWD application provides the enhanced wellbore geometry needed to design and engineer solutions using maximum size (OD) conventional casing, liners, expandable casing and multiple swellable packers. This type of assembly for drilling /completion design, currently utilized in multiple Williston Basin wells, ND, is shown to consistently result in shorter drilling time and successful first casing/liner runs. Currently this type of cross functional approach has been used on over 300 wells/ 3,000,000 ft. of lateral.
Eagle Ford Completion Optimization Using Horizontal Log Data
Authors: Slocombe R. , Acock A. , Fisher K. , Viswanathan A. , Chadwick C. , Reischman R. , Wigger E. 
Published: June 2014

Abstract
Schlumberger and four Eagle Ford Shale Play operators drilling in South Texas joined a consortium initiative to acquire various types of open hole logging data in several horizontal wells, and use the data to design the completions with optimum fracture stage and perforation cluster positioning. Horizontal production logs were subsequently used to gauge the effectiveness of using the log data to engineer the completions. This paper outlines the data acquisition techniques, analyses made on that data, application, results and conclusion.
Previous work carried out on production logging data acquired in several shale plays including the Eagle Ford (Miller et al, 2011) shows a significant variation in perforation cluster contribution. Other documented results showing the effect of targeting similarly stressed rock for fracture treatments (Waters, Heinze, Jackson, 2011) in the Marcellus. The objective of this study was to improve the initial flow capacity of the well by increasing the number of perforation clusters contributing to production. A related objective was to determine the optimal horizontal logging program that was needed to characterize the rock with minimal interruption to existing work flows.
This paper will show the results of data acquired over 12 horizontal wells in the Eagle Ford Shale (see map in figure 1). Petrophysical and geomechanical analyses were based on horizontal logging measurements and used as inputs to an engineered completion design tool that generated a recommendation on each well design. The design tool grouped intervals with similar properties for stimulation treatment. Following the treatment, horizontal production logs were run through the zones to measure the perforation cluster contribution.
The results of the study have the potential to change the way Unconventional Resources are developed. Recent trends have seen a shift away from data acquisition to blind geometrical fracturing. This paper examines the value of acquiring petrophysical data in the lateral section and its application to completion optimization, the minimization of wasted resources, and the impact on early production.
Frac Pack Completion Scorecard: The Importance of Scoring High
Authors: Marquez Maricel , Knobles Mark , Norman Wm. David , Oudtshoorn Cobus , Naha Susmito 
Published: June 2014

Abstract
Frac packing is one of the preferred completion techniques for deepwater wells in need of sand control. Frac pack completion performance and reliability can have a significant impact on the economic viability and profitability of a project, particularly for deepwater developments where the cost of intervention and completion failure can be very high. This work discusses key lessons learned and best practices identified from look back studies conducted on frac pack completions in deepwater fields across the world. The frac pack completion scorecard, a tool that provides a normalized means to evaluate the quality of the completion, thus avoiding possible bias based on reservoir parameters or wellbore architecture, focuses on key aspects of the well design and installation process, including rock stresses and well orientation, debris management, perforating, frac design and execution, fluid loss management, and mechanical issues with hardware components. The tool has been validated with data collected from more than 100 wells over a period of eight years, and has proved to be a valuable workflow for root cause analyses to identify probable causes for sand control completion failures, increasing skins and declining productivity index (PI) values over time. It has also been effectively used as a predictive tool for future well performance and to make data-driven, risk-weighted decisions concerning well deliverability thresholds. When the design and installation processes and procedures are shaped around scoring well on the scorecard, the results are better wells not only initially, but for the life of the project.
Effect of Concentration on HPAM Retention in Porous Media
Authors: Zhang Guoyin , Seright R.S.. S. 
Published: June 2014

Summary
This paper investigates the effect of hydrolyzed polyacrylamide (HPAM) polymer concentration on retention in porous media by use of both static and dynamic measurements. Consistent results by use of these two methods show that different polymer-retention behaviors exist in dilute, semidilute, and concentrated regions. In both the dilute and concentrated regions, polymer retention has little dependence on concentration. In contrast, in the semidilute region, polymer retention is concentration dependent. If a porous medium is first contacted sufficiently with dilute polymer solution to satisfy the retention, no significant additional retention occurs during exposure to higher HPAM concentrations. On the basis of the experimental results, a concentration-related retention mechanism is proposed that considers the orientation of the adsorbed polymer molecules and the interaction between molecular coils in solution. By use of this model, we explain why polymer retention does not show much dependence on concentration in the dilute and concentrated regimes. Further, in the semidilute region, we explain how moderate coil interactions lead to mixed adsorbed-polymer orientation and magnitude on rock surfaces, and retention becomes concentration dependent. In field applications of polymer and chemical floods, reduced polymer retention may be achieved by first injecting a low-concentration polymer bank.
Compositional Modeling of Tight Oil Using Dynamic Nanopore Properties
Authors: Wang Yuhe , Yan Bicheng , Killough John 
Published: June 2014

Abstract
A typical tight oil reservoir such as the Bakken has matrix pore sizes ranging from 10 nm to 50 nm. At such small scales the confined hydrocarbon phase behavior deviates from bulk measurements due to the effect of capillary pressure. In addition, compaction of pore space can bring about order of magnitude changes for tight oil formation properties during pressure depletion further exacerbating these deviations. Without considering these facts a conventional reservoir simulator will likely not be able to explain the inconsistent produced GOR observed in the field compared to simulated results. The effect of these inaccuracies on ultimate recovery estimation can be devastating to the underlying economics.
This paper presents a compositional tight oil simulator that rigorously models pressure dependent nanopore-impacted rock and fluid properties, such as suppression of bubble point pressure, decrease of liquid density, and reduction of oil viscosity as well as their interactions with pore space compaction. The cubic Peng-Robinson equation of state is used for phase behavior calculations. Capillary pressure is evaluated by standard Leverett J-function for porous media. Modifications to the stability test and two-phase split flash calculation algorithms are provided to consider the capillarity effect on vapor-liquid equilibrium.
The simulator can capture the pressure-dependent impact of the nanopore structure on rock and fluid properties. As a result, the problem of inconsistent GOR is resolved and the history matching process is greatly facilitated. It is shown that inclusion of these enhanced physics in the simulation will lead to significant improvements in field operation decision-making and greatly enhance the reliability of recovery predictions.
The Risk of Using Risk Matrices
Authors: Thomas Philip , Bratvold Reidar B. , Eric Bickel J.. 
Published: June 2014

SummaryThe risk matrix (RM) is a widely espoused approach to assess and analyze risks in the oil and gas (O&G) industry. RMs have been implemented throughout that industry and are used extensively in risk-management contexts. This is evidenced by numerous SPE papers documenting RMs as the primary risk-management tool. Yet, despite this extensive use, the key question remains to be addressed: Does the use of RMs guide us to make optimal (or even better) risk-management decisions?We have reviewed 30 SPE papers as well as several risk-management standards that illustrate and discuss the use of RMs in a variety of risk-management contexts, including health, safety, and environment (HSE), financial; and inspection. These papers promote the use of RMs as a “best practice.” Unfortunately, they do not discuss alternative methods or the benefits and detriments of the use of RMs.The perceived benefit of the RM is its intuitive appeal and simplicity. RMs are supposedly easy to construct, easy to explain, and easy to score. They even might appear authoritative and intellectually rigorous. However, the development of RMs has taken place completely isolated from scientific research in decision making and risk management. This paper discusses and illustrates how RMs produce arbitrary decisions and risk-management actions. These problems cannot be overcome because they are inherent in the structure of RMs. In their place, we recommend that O&G professionals rely on risk- and decision-analytic methods that rest on 250 years of scientific thought and testing.
Estimation of Effective Fracture Volume Using Water Flowback and Production Data for Shale Gas Wells
Authors: Alkouh Ahmad , McKetta Steven , Wattenbarger Robert A. 
Published: June 2014

Abstract
Gas production data may be the main tool used to analyze shale gas reservoirs. Water production is usually not included in the analysis. In this paper, post-frac water flowback and long-term water production are added to the analysis. These water data are usually available but are analyzed separately and not combined with long-term gas production data. In this paper, procedures and examples are presented for including water flowback and water production data in the analysis of shale gas wells using rate transient analysis.
A number of simulation cases were run. Various physical assumptions were used for the saturations and properties that exist in the fracture/matrix system after hydraulic fracturing. Water flowback and long-term production periods were then simulated. The results of these simulations were compared with data from actual wells using diagnostic and specialized plots. These comparisons lead to certain conclusions which describe well/reservoir conditions after hydraulic fracturing and during production.
This paper shows the benefits of a new method for combining water flowback and long-term water production data in shale gas analysis. Water production analysis can provide effective fracture volume which was confirmed by the cumulative produced water. This will help when evaluating fracture-stimulation jobs. It also shows some pitfalls of ignoring flowback data. In some cases the time shift on diagnostic plots changes the apparent flow regime identification of the early gas production data as well as water production data. This leads to different models of the fracture/matrix system. The presented work shows the importance of including water flowback data in the long-term production analysis.
Enhanced Oil Recovery in Gas-Flooded, Carbonate Reservoirs by Wettability-Altering Surfactants
Authors: Wang Leizheng , Mohanty Kishore 
Published: June 2014

Abstract
Gas aided gravity drainage is a common oil recovery technique in anticline-shaped oil reservoirs. If the permeability is low and the reservoir is oil-wet, the remaining oil saturation can be quite high. The goal of this work is to mobilize a part of this oil by surfactant injection. Different coreflood strategies including Gas-Surfactant-Gas (GSG), Gas-Water-Surfactant-Water (GWSW), Gas-Surfactant-Water (GSW), and Gas-Surfactant-Water-Gas (GSWG) floods were investigated. GSG, GWSW and GSWG corefloods conducted in limestone cores recovered about 40-50% of the original oil in place (OOIP) due to the injection of surfactant. GSW corefloods conducted in a vuggy dolomite recovered less, about 20% OOIP incrementally. A 2D conceptual simulation model was built for an anticline reservoir for gas and surfactant solution injection. GSG flooding using wettability altering surfactant exhibited high oil recovery at the field-scale. IFT reduction, wettability alteration, and foam formation contributed to enhanced oil recovery.