bluuebunny/crossref_metadata_2025_split huggingface dataset:
Borehole Design: Stability Considerations
Authors: Gil Ivan , Roegiers Jean-Claude 
Published: December 2007

Abstract
In recent years drilling for hydrocarbons have become a much more challenging task as nice, blanket-type reservoirs are now part of history and appear mostly in textbooks and old reports. The current economic and political world environment demands fewer, more "difficult" wells to be drilled and produced. Wellbore stability problems account for huge over-costs worldwide.
Tectonically active areas, thin interlayered horizons, unconsolidated rocks; deep and hot formations are part of the geological environments where hydrocarbons are currently produced from. The degree of planning and problem anticipation at both drilling and production stages will determine the difference between a productive reservoir and a technical/economical failure.
In the literature, some specific cases have been analyzed but the lack of a more general methodology for wellbore design is a problem that needs to be addressed. The vast majority of models utilize two-dimensional (2D) descriptions of the problem in order to determine the best well trajectory from a geomechanical point of view. In this paper, several situations are presented, where different stress field patterns were assumed for different rock types. The generality of this study provides a tool for well design under different stress environments. The maximum principal stress was allowed to follow different directions in different planes (horizontal, vertical and inclined) depending upon the case being analyzed.
The model represents wellbores drilled in shallow, medium-deep, and deep basins. The effect of both differential stress and loads magnitude were evaluated throughout this work.
The model developed here was based on the finite element method, for both linear-elastic and elasto-plastic materials. The description of the problem is a fully three-dimensional (3D) representation of the wellbore and the applied stresses. This paper has two parts: a theoretical approach, which provides the basis for the solution setup, and a set of numerical experiments with their correspondent results. Since several real-life situations were evaluated, the potential applicability of the results obtained here is apparent; and the results of these simulations could be used as a cross check for calculations made for more particular situations in the field. The aim of this work is to provide a more global vision of the effects of stress variations upon the optimum design of oil and gas wells.
Experimental Study of Hydraulic Fracture Initiation in Colton Sandstone
Authors: Lhomme T. P. , de Pater C. J. , Helfferich P. H. 
Published: December 2007

Abstract
We performed laboratory scale experiments for the study of horizontal fluid driven fracture initiation from an open-hole section. In order to clarify the role of material microstructure and fluid infiltration, we used viscous Newtonian fluids to initiate penny shaped fractures from radial notches in blocks of natural sandstone. We varied the fluid viscosity and injection rate over ranges allowing for significant fluid losses toward the dry porous rock. For low efficiency fluids, the fracture propagation was characterized by non-monotonic pressure variations. We propose a formulation of the problem of hydraulic fracture initiation in an elastic homogeneous permeable material. Our model accounts for fluid losses toward the rock and a cohesive zone at the fracture tip. We performed dimensional analysis in order to lump the physical parameters into meaningful dimensionless groups. Scale effects concerning the fluid efficiency, decompression effects and material failure could be predicted from dimensional analysis and corroborated with experimental observations. We also propose a numerical solution for this model. The numerical results compare well with experimental results. This work provides a proper scaling for hydraulic fracture initiation. This scaling is necessary for comparing laboratory scale results to field observations.
New Iterative Coupling between a Reservoir Simulator and a Geomechanics Module
Authors: Tran David , Settari Antonin , Nghiem Long 
Published: December 2007

Abstract
Interactions of solid mechanics and fluid flow have been studied by numerous researchers for the past several years. Different methods of coupling such as full coupling, iterative coupling, etc., have been used. Nevertheless, the accuracy and the large run time of the coupled solid-mechanics fluid-flow model are outstanding issues that prevent the application of the coupled model in full-field studies. In this work, a novel relationship of porosity as a function of pressure, temperature and mean total stress is developed for iterative coupling of stress and flow. The new formula not only improves the accuracy of the coupling, but also reduces substantially the number of coupling iterations. The latter feature decreases significantly the CPU time. The new approach was implemented in a modular, iteratively coupled system. The rapid convergence provides the equivalent of a fully coupled method that is necessary to investigate complex coupled problems. The main advantage of this type of coupling is that a geomechanics module can be easily coupled with different reservoir simulators. The paper gives some comparisons of results obtained by the new porosity formula with another formulation.
Continuum Damage Theories and Petroleum Geomechanics
Authors: Cheng Harry H. , Dusseault Maurice B. 
Published: December 2007

Abstract
We present a new continuum damage mechanics constitutive model for brittle geomaterials based on irreversible thermodynamics with internal state variables. Damage is incorporated by a vector-valued internal state variable that can be interpreted as the local void density in a cross-section with normal n within a representative material volume element. The thermodynamic basis, free energy function, damage evolution equation, and damage-induced inelastic compliance are derived. It is shown that damage causes strain-softening and positive dilatancy, as well as decrease of the material stiffness. Comparisons of the model predictions with well-known experimental data on rocks and concrete under uniaxial and triaxial compression stresses are given. This model could be valuable in appropriate Petroleum Geomechanics cases.
Accidental Geomechanics - Capturing In-situ Stress from Mud Losses Encountered while Drilling
Authors: Edwards S. T. , Bratton T. R. , Standifird W. B. 
Published: December 2007

Abstract
The accurate determination of minimum horizontal stress magnitudes (Sh) can be critical to the economic success of oilfield operations from exploration through abandonment. Sh magnitudes are needed to optimally design drilling, completion and workover operations. While Sh magnitudes could be determined from a well-designed stress test, they are typically estimated from leak-off tests. These estimates are often inaccurate due to the different mechanisms affecting the leak-off pressure (LOP). These factors include among others the possible existence of natural or drilling induced fractures, the unknown stress concentration surrounding the wellbore, and the variability in test procedures used. These factors lead to significant differences between reported LOPs and Sh.
However, high quality stress measurements are often "accidentally" made while drilling. Most mud loss events characterized by wellbore ballooning, simulate an extended leak-off test, a high-quality stress test yielding an accurate value of Sh1. Wellbore ballooning is a term used to describe mud losses when the mud pumps are turned on followed by mud gains when the mud pumps are turned off. Wellbore ballooning is often caused by the opening and closing of fractures2,3. When circulating, the higher wellbore pressure opens and propagates the fractures and when circulation stops, the lower wellbore pressure closes the fracture returning mud to the wellbore. Fracture opening and closing pressures are better estimates of Sh, and can be quantified using downhole annular pressure while drilling measurements (APWD). Because circulation often starts and stops multiple times, multiple opening and closing pressures are recorded. The addition of time-lapse resistivity to locate the fractures completes this elegant and high quality stress measurement technique.
Examples are presented from 2 GOM wells where fractures in both sands and shales have been responsible for ballooning. Annular pressures measurements are then analyzed to determine Sh.
Application of Risk Analysis to Assessment of Casing Integrity and Subsidence in Deepwater Reservoirs
Authors: Abou-Sayed A. S. , Noble J. E. , Guo Q. , Meng F. 
Published: December 2007

AbstractVarious geomechanical-modeling approaches, which cover a wide range of techniques and complexity, have been developed to assess the stability of a borehole and/or the integrity of well casing. The ability to confidently use these models can be limited, however, because they generally do not allow the model user to consider the "real-world" variability of the input parameters defined in the models. Often, these geomechanical models do not adequately accommodate the innate variability of the rock properties (mechanical and petrophysical) of the target reservoirs. Consequently, this deterministic approach too often results in uncertainty about the "correct" value of a critical parameter to use and insecurity in the model results. Decisions based on these results can later, not surprisingly, be found to be incorrect. Model users attempting to overcome the limitations noted above have tried various techniques. Subjective estimation, arbitrary "minimums", grading techniques, and stepwise estimation have all been commonly used.Recently, more powerful techniques such as Monte Carlo simulation and decision analysis have come into popular use. Over the past decade these two techniques have been extensively used in the petroleum industry to evaluate and solve a wide range of analytical problems in reservoir engineering and the geosciences. In this paper, the application of these techniques to a number of generalized geomechanical problems will be illustrated. A Monte Carlo simulation enables the user to identify, measure or estimate, and evaluate uncertainties in the problems being analyzed. The simulation models the random behavior of the input variables much like in a game of chance. That is, the variables have an uncertain value within a known range for any particular time or event. Numerical model and software packages are developed based on the Green's function for a nucleus of strain in the reservoir. The model is coupled with reservoir simulations to evaluate pressure maintenance and reservoir development schedule effect on casing integrity, fault stability via sensitivity studies. The geomechanics solutions would be coupled with both commercial or in-house developed reservoir simulators. The results of multiple simulations, done to determine the most likely outcome of various wellbore solution options, are reported in the current paper.
Characterization of Shales for Drilling Purposes
Authors: da Fontoura Sergio A. B. , Rabe Claudio , Lomba Rosana F. T. 
Published: December 2007

Abstract
This paper describes an integrated methodology to characterize shales from an engineering point of view. Shale samples from offshore Brazil were used throughout the study. The proposed methodology includes laboratory tests designed to characterize the rock individual constituents, i.e., solid particles and pore fluid, and to describe the rock microstructure. Complementary laboratory tests on the same materials indicated low potential of reactivity when in contact with saline solutions in spite of the presence of highly expansive clay minerals. The paper suggests that other elements besides simply the characteristics of the clay minerals should be considered when evaluating the potential of reactivity of shales.
Development of an Orthotropic 3D Elastoplastic Material Model for Shale
Authors: Crook Anthony J. L. , Yu Jian-Guo , Willson Stephen M. 
Published: December 2007

Abstract
Shales encountered in the overburden above hydrocarbon reservoirs often pose challenges to the stability of boreholes. Consequently, there is a keen interest in borehole stability prediction, which is complicated by the laminated structure of shale that arises as a consequence of the depositional environment.
A combined experimental/numerical investigation is being undertaken to address how the directional properties of shale impact borehole stability in weak shale formations. Within this paper an advanced finite element procedure for simulation of progressive damage of orthotropic pressure-sensitive materials is presented, which includes bifurcation and post-bifurcation analysis. This constitutive model is based on critical state theory and is specifically designed to represent the characteristic deformation of weak shale formations. It includes orthotropic elasticity and an orthotropic pressure-dependent yield surface that is curved in the p-q plane, and which intercepts the hydrostatic axis in both tension and compression. A regularization procedure is also presented that ensures mesh invariance and correctly reproduces the dependence of strength on the size of the test specimen.
Calibration of the model parameters is also discussed and the model is validated by comparison with the results of uniaxial and triaxial compression tests for Pierre I Shale performed at different bedding plane orientations.
Quantifying Value Creation from Intelligent Completion Technology Implementation
Authors: Sharma A. K. , Chorn L. G. , Han J. , Rajagopalan S. 
Published: December 2007

Abstract
Oil and gas development is fraught with technical uncertainty. As hard as we try, subsurface anomalies continue to surprise the most gifted petroleum engineers, and as a result, we seek technology that can help manage reservoir uncertainty. A classic success story is 3D seismic technology, which has proven to enhance our reservoir knowledge and reduce capital investment uncertainty. Intelligent Well Technology is much the same, in that it reduces the negative effects of reservoir uncertainty on expected future production and cash flow.
Intelligent Well technology can provide an operator continuous/permanent down-hole monitoring coupled with the ability to reconfigure the well completion upon demand (through remotely operated flow control) without additional investment in response to reservoir knowledge gained over time. This ability creates value through reduced well intervention costs, reduced operating costs (i.e. through reduced surface facility requirements), reduced capital expenditures through innovative Intelligent Well Field Development Programs, increased production through commingling and increased recovery through enhanced reservoir surveillance and management. Moreover, the combined capabilities of real-time monitoring and flow control allow an operator the flexibility to actively respond to unforeseen reservoir driven events (i.e. early gas/water breakthrough or coning), effectively reducing future cash flow uncertainty.
Traditional discounted cash flow (DCF) models do not adequately value the benefits of operational flexibility, and thus often underestimate the value of intelligent well technology (i.e. the benefits of real-time monitoring and control).1 Real Option analysis has been shown to effectively quantify this value in cases regarding portfolio analysis and corporate capital management.2
In this paper, we describe a method to apply Real Options theory to quantify the value of Intelligent Well applications, including the value of reducing project volatility and risk. We derive the mathematics to quantify Intelligent Well value for four specific case scenarios and outline the methodology to manage more complex cases. Finally, we describe how the mathematical model can be incorporated into a larger workflow process to assess entire asset portfolios for potential Intelligent Well applications.
An Investigation of the Economic Benefit of Inflow Control Devices on Horizontal Well Completions Using a Reservoir-Wellbore Coupled Model
Authors: Augustine Jody R. 
Published: December 2007

AbstractA finite-difference, lumped-parameter based, reservoir-wellbore coupled model was developed to characterize the economic benefit of inflow control devices on horizontal well completions. Baker Oil Tools' inflow control device (ICD), the Equalizer™, has been tested and analyzed as a standalone entity. Several correlations have been developed to quantify the pressure drop characteristics of this ICD. To show the positive effects an ICD has on an asset, one must quantify, not only the flow performance of the ICD, but the time dependent depletion scenarios of the reservoir in question.In this paper, the benefits of a unique inflow control device will be shown by analyzing reservoir depletion scenarios with and without inflow control. Without inflow control, a horizontal completion is at risk of early water breakthrough. With early water breakthrough, the water cut tends to escalate due to its lower viscosity compared to that of oil. As the water cut escalates, oil production drops significantly, often leading to shutdown of the well and reserves being left in the ground. This paper will show the benefits of using an ICD by describing the model development of a hypothetical, yet typical, field and the subsequent analysis that drives the completion design of the horizontal well.The model includes the reservoir, water oil contact, near-wellbore characteristics, wellbore, sand control screen, ICDs, basepipe, and production tubing, capital expenditure input, and real time calculations of net present value of the reservoir. The use of inflow control devices increases the capital expenditure, but the increased cost is more than compensated for by the increased production efficiency.The technology presented can be extrapolated and applied to the analysis of well completions consisting of different types of hardware. Future developments of this type of analysis will be described.This work provides three additions to the technical knowledge base of the petroleum industry; 1) use of a lumped-parameter finite-difference based model to couple the wellbore completion to the reservoir, 2) proof of the positive effects of inflow control devices on producing hydrocarbons, and 3) further information on using the "economics of reservoir depletion" to drive horizontal completion designs.
Swelling Packer for Zonal Isolation in Open Hole Screen Completions
Authors: Freyer Rune , Huse Arve 
Published: December 2007

Abstract
Open hole screen completions are efficient in installation and reliable in use if designed properly. The major weakness of Open Hole screen completions have been lack of zonal isolation. An Open Hole Zonal Isolation packer has been developed and installed in 5 wells with up to 14 packers per well. No downtime, operational time or installation failures were experienced. The packer construction is based on the swelling properties of rubbers with crude oil.
New Relationship Between Oil Company and Service Company Rejuvenates a Mature North Sea Gas Field
Authors: McIninch Bruce , McIntyre Alistair , Gulrajani Sunil , Norris Mark 
Published: December 2007

AbstractMany of the once prolific North Sea reservoirs have been reduced to mature assets, with a majority having reserves down to a fraction of their initial value. A significant number of isolated pockets of hydrocarbon bearing sands, however, remain available for production. The advantage of pursuing such bypassed assets is the availability of an existing infrastructure to support any incremental production. The biggest challenge when considering production enhancement initiatives is the marginal nature of the associated economics combined with project risk. In addition, marginal and mature assets seldom generate required engineering firepower to solve complex problems. Lack of investment results in decreased production and downward spiral that only can result in often-premature field abandonment.This paper describes how Marathon identified a requirement for an alternative commercial arrangement and together with a selected service company, built an effective team that rejuvenated a dwindling gas asset. An interdisciplinary study was initially undertaken to quantify and manage economical risk associated with this project. Previous attempts at rejuvenating production were revisited to assess reasons for their ineffectiveness, or success. An alternative commercial model was then applied to help overcome the marginal nature of the economics. A data acquisition campaign was subsequently undertaken to determine the optimum intervention alternatives. Successful execution of the intervention activities has delivered a two-fold increase to total field production.Several recently introduced technologies were employed during the course of the project. The project also spawned multiple field practices. Their conceptualization, field implementation and long-term effects on production are also described.Contributions. This paper will present the application and results from several initiatives, including: Descriptions of an alternative commercial model, where the operator and service company mutually participate in the project risk, and its rewards.Implementation of the lift-log procedure, a single trip, combined, coiled tubing N2-lift and production logging operation.Utilization of scale-inhibitor impregnated proppant. This specialized proppant prevents loss of conductivity due to scale deposition within a fracture.Technical, commercial and operational best practices for use with mature field rehabilitation projects.
Imaging Gravel-Pack Quality: Application to Deviated and Horizontal Wells
Authors: Gulrajani Sunil N. , Pittman Dennis , Herve Xavier 
Published: December 2007

Abstract
Horizontal well gravel-packing operations are known to exhibit a higher rate of premature screenout. The suggested causes of such failure range from extreme reservoir conditions (e.g., low in-situ stresses), to suboptimal drilling practices (e.g., extensive washouts), or even to limitations of the gravel placement process (i.e., accelerated carrier fluid leakoff). Premature screenouts are postulated with theoretical studies or with laboratory experiments. These approaches rely on idealized assumptions and therefore fail to explain gravel placement behavior observed in field practice. Further, currently available gravel-pack logging tools can provide only borehole-averaged measurements. These are inadequate in horizontal wells where the gravel-pack quality may not be radially uniform. In horizontal wells, an azimuthal, or localized, gravel-pack measurement is necessary for a proper understanding of the gravel deposition over the reservoir section.
This paper describes the development and application of a new gravel-pack logging procedure. The associated logging tool is based on a radically different concept of fullbore gravel-pack imaging. It focuses on discrete sectors around the wellbore, providing the ability to azimuthally measure the gravel-pack quality. Further, its combinability with other production-logging sensors ensures that all parameters pertinent to gravel-pack evaluation can be obtained using a short, compact toolstring with minimal logging time.
The gravel-pack tool can also be operated in memory mode and deployed with certain downhole completion components (i.e., the washpipe) before gravel injection. These components are normally retrieved upon completion of the pumping operation, bringing the logging tool through the gravel pack and back to surface. One can therefore obtain a gravel-pack log concurrently with the gravel placement procedure. This "logging while completing" approach will provide an enhanced gravel-pack quality measurement at a fraction of the cost of conventional electric line logging operations.
Multiple field examples that illustrate the field application of this logging tool are provided. The paper also provides field evidence of the gravel placement failure mechanisms that have been previously postulated by theoretical studies.