bluuebunny/crossref_metadata_2025_split huggingface dataset:
Experimental Study of Polymer-free and Polymer-added Foams for Underbalanced Drilling: Are Two Foam-Flow Regimes Still There?
Authors: Edrisi A. R. , Gajbhiye R. N. , Kam S. I. 
Published: October 2012

Abstract
Foam-assisted underbalanced drilling technique is advantageous over the traditional overbalanced drilling near the productive water-sensitive formations due to its reduced formation damage, improved rate of penetration, higher cutting-transport capacity, and lower circulation losses. However, the complicated nature of foam rheology has been a major impediment to the optimal design of field applications.
Earlier studies with surfactant foams without oils and polymers show that foam flow in pipe can be represented by two different flow regimes: the low-quality regime showing either plug-flow or segregated-flow pattern, and the high-quality regime showing slug-flow pattern. The objective of this study is to investigate foam flow characteristics in horizontal pipes at different injection conditions, with or without oils, by using polymer-free and polymer-added surfactant foams.
The results of this study were presented in two different ways: (i) steady-state pressure drops (or, apparent foam viscosity, equivalently) measured by multiple pressure taps and (ii) visualization of bubble size, size distribution and flow patterns in transparent pipes. The results with surfactant foams and oil showed that (i) oil reduced the stability of foams in pipes, hence, decreasing the steady-state pressure drops and foam viscosities, and (ii) the presence of oil tended to lower the transition between the high-quality and the low-quality regimes (i.e., lower foam quality at the boundary, or lower fg* equivalently). In addition, the results with surfactant foams with polymer showed that (i) polymer thickened the liquid phase and, if enough agitation was supplied, could make foams long-lived and improve foam viscosities, and (ii) the system sometimes did not reach the steady state readily, showing systematic oscillations. In both cases, though, the experiments carried out in this study showed the presence of two distinct high-quality and low-quality flow regimes.
Link between Rocks, Hydraulic Fracturing, Economics, Environment, and the Global Gas Portfolio
Authors: Aguilera Roberto F. , Ripple Ronald D. 
Published: October 2012

Abstract
This paper presents a methodology for connecting geology, hydraulic fracturing, economics, environment and the global natural gas endowment in conventional, tight, shale and coalbed methane (CBM) reservoirs. The volumetric estimates are generated by a variable shape distribution model (VSD). The VSD has been shown in the past to be useful for the evaluation of conventional and tight gas reservoirs. However, this is the first paper in which the method is used to also include shale gas and CBM formations.. Results indicate a total gas endowment of 70000 tcf, split between 15000 tcf in conventional reservoirs, 15000 tcf in tight gas, 30000 tcf in shale gas and 10000 tcf in CBM reservoirs. Thus, natural gas formations have potential to provide a significant contribution to global energy demand estimated at approximately 790 quads by 2035.
A common thread between unconventional formations is that nearly all of them must be hydraulically fractured to attain commercial production. A significant volume of data indicates that the probabilities of hydraulic fracturing (fracking) fluids and/or methane contaminating ground water through the hydraulically-created fractures are very low. Since fracking has also raised questions about the economic viability of producing unconventional gas in some parts of the world, supply cost curves are estimated in this paper for the global gas portfolio. The curves show that, in some cases, the costs of producing gas from unconventional reservoirs are comparable to those of conventional gas.
The conclusion is that there is enough natural gas to supply the energy market for nearly 400 years at current rates of consumption and 110 years with a growth rate in production of 2% per year. With appropriate regulation, this may be done safely, commercially, and in a manner that is more benign to the environment as compared with other fossil fuels.
Well Construction Optimization in the Montney Formation in the Karr Kakwa Area of Central Western Alberta: A Case Study
Authors: Teichrob Bob , Hucik Barry , Shirkavand Farid , Schmitz Ron , Haysom Steve , Nevokshonoff Glen 
Published: October 2012

Abstract
Seven Generations Energy Ltd. (7Gen) has drilled several horizontal wells in the extremely liquids rich Montney formation in the Karr Kakwa area of central western Alberta. Over the last two years we have seen progressively shorter drilling times as well as a marked increase in production as a function of optimal hydraulic fracturing recipes and completion installations. This paper will discuss the systematic approach taken by well construction engineers to optimize drilling performance through bit selection coupled with vibration mitigation and hydraulics optimization. Further technologies that will be discussed and will/have been be implemented are torque mitigation technologies to mitigate stick slip and the use of managed pressure drilling techniques to decrease mud density and further increase ROP’s. This paper will also discuss the coincident work done to optimize fracture treatments as a function of rock strength and measured gas response while drilling.
Nanostructure vs. Macroscopic Properties of Mancos Shale
Authors: Torsaeter M. , Vullum P. E. , Nes O.-M. , Rinna J. 
Published: October 2012

Abstract
Shale gas reservoirs have become financially attractive upon more efficient utilization of technologies such as horizontal drilling and hydraulic fracturing. In order to better identify such reservoirs, estimate their production potential, as well as device optimum drilling and fracturing strategies, a detailed understanding of the connection between gas shale macroscopic mechanical and petrophyscal properties and microstructure is highly valuable. Since a high fraction of both pores and grain structures in gas shales are of nanometer sizes, this requires advanced experimental techniques beyond what has commonly been applied on more conventional coarsely grained reservoir rocks. We present a study of the Mancos outcrop shale where we combine results from state-of-the-art nano tomography with results from standard rock mechanical, petrophysical, and geochemical testing. In addition to providing the first detailed investigation of the Mancos shale on the nanometer pore scale, this multi-scale analysis contributes to bridging the gap between small- and large-scale gas shale descriptions – and to establish the role of nano tomography in relation to more standard rock testing procedures. Our study revealed that the Mancos shale is marginally mature (%Ro ~ 0.66–0.70), gas prone and has a total organic content of 1.0–1.3 wt%. It is observed that even if the porosity of the organic matter itself is very low, organics are found in or around all analyzed fractures and voids in the Mancos sample. Large fractures parallel to bedding are observed to be organic-rich, potentially enabling the soft organic material to serve as a preferential weak plane when the rock is subjected to mechanical stress. This may be reflected in the observed significant strength anisotropy of about 60% deduced from rock mechanical tests on the same material. It is also suggested that nano/microfractures influence the measured acoustic properties, which appear consistent with those of other organic rich shales. Thus, knowledge of the detailed nanostructure, especially the distribution of organic matter, its porosity and its interface towards other solid phases, may be beneficial when attempting to predict shale macroscopic mechanical and petrophysical properties. Knowing these simplifies the process of identification and characterization of shale gas prospects, as well as the subsequent drilling and production.
Dynamic Cementation Improves Wellbore Construction and Reduces the Hazards of Groundwater Contamination in Shale Plays
Authors: Holt C. , Lahoti N. 
Published: October 2012

Abstract
The well construction process only allows one chance to install a primary cementing system. The industry has long understood the advantages of the method of pipe movement during cementing operations, yet it is not commonly practiced in spite of API recommendations. One barrier to implementing this methodology has been the availability of tools and technology. Application of a modern casing running tool (CRT), with a top drive allows the casing string to be safely conveyed to bottom, and subsequently rotated and reciprocated during cementing.
The standard industry toolbox uses long bails attached to the traveling block, conventional casing elevators and a standard cement head. Practically, this does not allow for rotation during cementation. Rigging up this equipment is time consuming and leaves the pipe motionless on bottom. Cement jobs under these circumstances are more prone to failure and frequently require remedial cementing.
Most North American operators are drilling extended reach wells in the prolific onshore shale plays. Long laterals combined with tortuous wellbores make it difficult to conventionally run casing; as a result, usually these sections require casing rotation to pass through challenging trajectories and get to bottom. Moreover, the horizontal shale wells are often completed with multi-stage frac jobs. It is imperative to have high quality cement job to insure zonal isolation, otherwise communication between zones can occur; this can result in a lower quality frac job and well completion. A poor completion can result in lost production and leaks can lead to ground water contamination. After pumping stops, there is no known method to affect additional mud removal from continued pipe movement, but cement job quality is not dependent solely on mud removal.
The drilled section is of little value until it is cased and a competent cement job is completed. Dynamic Cementation™ consists of rotating and reciprocating the casing from the time the cement operation commences until cement is set. It can increase the quality of the cement job by increasing mud removal and decreasing pressure loss while cement cures. This paper discusses the benefits of casing movement during cementing, the methodology and results.
Rate Transient Analysis of Stress-Sensitive Formations during Transient Linear Flow Period
Authors: Qanbari F. , Clarkson C. R. 
Published: October 2012

Abstract
Rate- and pressure-transient analysis of unconventional gas and oil reservoirs is a challenge because of complex reservoir characteristics that dictate flow. An important flow regime for analysis of these reservoirs is transient linear flow, which can be associated with linear flow to induced hydraulic fractures or to horizontal wells. One of the complications in the analysis of this flow regime is stress-sensitivity of porosity and permeability. This work aims to provide a method for analyzing transient linear flow in reservoirs with stress-sensitive permeability.
Flow of a compressible fluid in a stress-sensitive formation is governed by a nonlinear second order partial differential equation (PDE) with nonlinearities in both the accumulation and flow differential terms. A version of the Kirchhoff transformation is used to make the accumulation term linear, while a monotonically varying nonlinearity (as a function of a new pseudopressure function introduced in this work) exists in the flow differential term. The transformation, however, does not introduce any nonlinearity to the constant-wellbore pressure-condition, which is the case for constant well flow rate.
An exact solution of the transformed nonlinear PDE is provided for pressure distribution and flow rate calculations. The results are compared with approximate solutions in which fluid and rock properties are considered to be constant and evaluated at a specified pressure, as obtained by the error function (erf) solution. The results show that, at the wellbore, the value of the slope of the square-root of time plot (reciprocal of flow rate vs. square-root of time) can be used to calculate one of the two parameters, permeability modulus or initial permeability. This is the case if the derivative of the Kirshhoff parameter with respect to the Boltzmann variable is known for different values of fluid and rock compressibility, permeability modulus, and pressure drawdown. In this study, the Fujita’s method is used to calculate the derivative for some ranges of the affecting parameters. The results are presented as plots which can be used for analyzing the production data.
Well Production Performance Analysis for Unconventional Shale Gas Reservoirs: A Conventional Approach
Authors: Hategan Florin , Hawkes Robert V. 
Published: October 2012

Abstract
Over the last several years, horizontal drilling and multi-stage hydraulic fracturing have become the norm across the industry and proved crucial for economic production of natural gas from unconventional shale gas and ultra tight sandstone reservoirs, also referred to as nano-Darcy reservoirs.
Following the success of the Barnett shale, horizontal drilling and multi-stage hydraulic fracturing has spread across North America with new emerging shale gas plays such as the Eagle Ford, Woodford, Haynesville, Marcellus, Utica, Horn River changing the industry’s landscaping. In the current economic environment of high drilling and completion costs, coupled with lower commodity prices, the economic success of shale gas developments has become reservoir specific.
Evaluation of well’s initial performance in a particular field and especially the ability to accurately predict the long term production behavior and EUR is critical to the efficient deployment of large capital investments. Field analogies making use of arbitrary "type curves" can have a significant negative impact on the project’s bottom line.
With the growing number of multi-stage horizontal wells producing from shale gas reservoirs, many "unconventional" production analysis techniques have been developed based on new concepts such as stimulated reservoir volume (SRV), fracture contact area (FCA), or sophisticated mathematical relationships (power law decline curves, linear flow type curves, to name a few). These sophisticated engineering processes are well documented in the literature and have been presented at numerous industry work shops and conferences. However, for the majority of these techniques there is one common reoccurring theme: performance evaluation of shale gas production cannot be analyzed using conventional methods (e.g. Darcy’s Law).
This paper will demonstrate how the conventional approach of reservoir characterization, well performance evaluation and forecasting, can be implemented for all unconventional gas reservoirs, using traditional well testing and production data analysis techniques. We will present one simple analytical model based on the solution of the pseudo steady state equation and will introduce the concept of a shale gas normalized production plot. In our view, the shale gas normalized production plot is one type curve generally applicable to any shale gas reservoir.
Finally, pre-frac in-situ testing techniques will be reviewed and special consideration will be given to the perforation inflow diagnostic (PID) testing. We will emphasize the importance of specific reservoir parameters (pore pressure and in-situ shale matrix permeability) and show their impact on drilling and completion strategy and design. Field case examples including well test results and production data from wells completed in several shale gas reservoirs are presented.
Parametric Sensitivity Study of Chemo-Poro-Elastic Wellbore Stability Considering Transversely Isotropic Effects in Shale Formations
Authors: Huang Lu , Yu Mengjiao , Miska Stefan , Takach Nicholas , Bloys J. B. 
Published: October 2012

Abstract
A chemo-poro-elastic wellbore stability model considering the shale transverse isotropic effect is developed. In poroelastic theory, the pore fluid motion and solid structure deformation are coupled. Lubinski’s one-way coupling scheme is adopted in this study which assumed a rock has strong structure and the effect of solid skeleton deformation on fluid flow is negligible.
It is found that normal stress along the cylindrical axis is affected by Young’s modulus on both the symmetrical plane and the axial direction.
A Taguchi orthogonal simulation design strategy is adopted to reduce the number of simulations while still achieving meaningful results. Analysis of variance (ANOVA) is conducted and parameter contributions to the mud weight window have been investigated. It can be found that among the 11 parameters of interest, wellbore inclination angle, hydraulic conductivity and water activity of drilling fluid play the most important roles in determining the mud weight window.
Knowledge of percentage contributions of the parameters in this chemo-poro-elastic wellbore stability model greatly helps drilling engineers identify the critical factors for wellbore stability control. This study also helps well trajectory design and drilling fluid optimization.
The Use of Electromagnetic Mixing Rules for Petrophysical Evaluation of Dual and Triple Porosity Reservoirs
Authors: Olusola Bukola K. , Guang Yu , Aguilera Roberto 
Published: October 2012

Abstract
Electromagnetic mixing rules of the type developed by Maxwell Garnett, Bruggeman, and the Coherent Potential formula are shown to be useful for evaluation of the porosity (or cementation) exponent, m, in naturally fractured reservoirs represented by dual and triple porosity models. Comparisons are made with core data from limestone, dolomite and tight gas reservoirs to corroborate results from the theoretical models.
Rigorous values of m reduce the uncertainty in calculated values of water saturation and hence improve estimates of hydrocarbons-in-place and recoveries particularly in situations where sufficient data are not available to utilize the material balance approach.
The main advantage of the new method developed in this paper for petrophysical analysis is that it can handle with the use of one single equation the individual mixing rules mentioned above, and at the same time quantify values of matrix, fracture and non- connected vug porosity, and the cementation exponent of the total porosity system.
It is concluded that electromagnetic mixing rules provide a useful methodology for petrophysical evaluation of complex dual and triple porosity reservoirs.
Updip Water Blockage in the Nikanassin Basin Centered Gas Accumulation, Western Canada Sedimentary Basin
Authors: Ramirez John F. , Aguilera Roberto 
Published: October 2012

Abstract
A basin centered gas accumulation (BCGA) is a "continuous petroleum accumulation" characterized by low permeability, the absence of downdip water, the absence of obvious traps and seals, the presence of pervasive gas or oil saturation over very large areas, abnormal pressures (either high or low), and the relative proximity to source rocks. The question is if it is reasonable to think that gas can be trapped over millions of years by an updip water block.
A reservoir simulation model has been created in order to answer this question. The water seal is shown to be the result of very low permeability and high capillary pressures, properties that are generally found in tight gas formations. The model is defined by a geometry that mimics the geologic interpretation of the Nikanassin BCGA in the Western Canada Sedimentary Basin (WCSB) and rock properties that provide a good representation of the real behavior of the reservoir in the Deep Basin. Different models were created trying to understand sensitivities to permeability and capillary pressure in the distribution of downdip gas and updip water over thousands of years. The results obtained appear consistent and reliable when compared with factual information from the Deep Basin.
The conclusion is reached that updip water blocks provide good seals in the Deep Basin. The simulation also confirms that special completion and stimulation practices are required in order to produce gas at economic rates from tight gas reservoirs.
Appraisal Excellence in Unconventional Reservoirs
Authors: Burkholder M. K. , Coopersmith E. M. , Schulze J. H. 
Published: October 2012

Abstract
Unconventional resource plays are breaking the rules of conventional decision wisdom. Rules of thumb developed over years of producing conventional assets are no longer always applicable and teams are struggling to uncover the new protocols. In unconventional, the demarcation line between appraisal and development is blurred as teams attempt to simultaneously hold acreage, explore, appraise and develop, ever striving to increase the pace to commercial sanction.
This paper presents a pragmatic approach to frame, evaluate and compare appraisal strategies in resource plays. The unique approach starts with framing the overall field appraisal plan, holistically, and then progresses to evaluating the most commonly encountered individual appraisal decisions, enabling teams to answer the following questions:
What are our key uncertainties and which appraisal options should we consider to resolve them? Is there value in running a pilot to determine the optimal well spacing and, if so, what is the best pilot design? Do we want to run a completions pilot and how should we configure it? Do we need to pilot where to and how to orient our laterals? Can we justify seismic to high grade our drilling program?
Appraisal framing is particularly valuable when taking on big acreage projects, helping teams identify new alternatives, organize options and look for interesting and innovative combinations. It also serves as a great tool to help teams work together. From surface to drilling, the process is inclusive, which is an important aspect in unconventional resources where cross discipline integration is so important.
The appraisal part of resource plays is as much or more about finding the exit points for different parts of the play as it is about learning and optimizing the commercial developments. Sometimes there may be no benefit of the new information from a Net Present Value (NPV) perspective and yet there is benefit to understanding the uncertainty reduction potential of different programs and knowing when projects are on the right path. This methodology is different than simply projecting learning curves on a development strategy and going forward. With this approach, teams clearly understand their walk points and rationale for them—helping compare different spending programs in order to understand and optimize recommended plans.
This paper provides an example of appraisal excellence in unconventional resource plays through an example which demonstrates some of the practical tips, tricks and tools which have proven to be effective for teams wrestling with these types of issues.