bluuebunny/crossref_metadata_2025_split huggingface dataset:
Anisotropic Stress Models Improve Completion Design in the Baxter Shale
Authors: Higgins Shannon , Goodwin Scott , Donald Adam , Bratton Tom , Tracy George 
Published: September 2008

Abstract
In unconventional reservoirs, stress models that account for anisotropy yield a stress profile which better represents in-situ conditions than the profile suggested by an isotropic stress model. Completion designs based on an accurate petrophysical model and stress profile which quantifies containment, influences perforating and staging strategies. This can help improve stimulation coverage from discreet shale intervals and lead to more economic completion decisions. This paper shows a comparison of stress magnitude estimated with a traditional linear poroelastic model from sonic data, with stress magnitude estimated from a model which accounts for transverse isotropy. A case study from the Baxter Shale play will show static and dynamic elastic moduli measured from core and acoustical logging, which vary significantly when measured in both the vertical and horizontal directions. The resultant stress profile estimated with a stress equation which accounts for this anisotropy better characterizes subtle stress changes that are significant for staging and perforating design in unconventional gas plays such as the Baxter Shale.
Advanced Wells: How to Make a Choice between Passive and Active Inflow-Control Completions
Authors: Birchenko V. M. , Al-Khelaiwi F. T. , Konopczynski M. R. , Davies D. R. 
Published: September 2008

Abstract
Horizontal and multi-lateral wells allow oil and gas companies to maximise contact with reservoir quality rock in either a single reservoir or multiple reservoirs. However they do not, by themselves, guarantee optimum reservoir drainage. Premature water or gas breakthroughs frequently occur due to: Reservoir permeability heterogeneity,Variations in distance between the wellbore and the fluid contacts, particularly in compartmentalized reservoirs,Variations in reservoir pressure in different regions of the reservoir penetrated by the wellbore.Pressure drop along the completion's flow path due to friction ("heel-toe" effect).
Many such well and reservoir management problems can be mitigated by installation of downhole flow control devices – "Active" Interval Control Valves (ICVs) and "Passive" Inflow Control Devices (ICDs). ICVs were initially employed for controlled, commingled production from multiple reservoirs; while ICDs were developed to counteract the "heel-toe" effect. The variety of reservoir applications for both technologies has proliferated so that their application areas now overlap. Appropriate selection between an ICV and an ICD completion can be both a complex and a time consuming process.
This paper compares the functionality and applicability of the two technologies. Completion Design selection guidelines are developed based on multiple criteria drawn from reservoir, production, operation and economic factors. Reservoir engineering aspects, such as uncertainty management, formation heterogeneity, and the level of flexibility required by the development are analyzed. Production and completion characteristics, such as tubing size, the number of separately controllable completion zones, the installation of multiple laterals and the value of real time information were also investigated. This systematic analysis forms the basis of a screening tool to identify the optimum technology for each particular situation.
This study provides a robust, comparative framework for both production technologists and reservoir engineers to select between passive and active flow control for optimised, advanced well completions.
Impact of Reservoir Uncertainty on Selection of Advanced Completion Type
Authors: Birchenko V. M. , Demyanov V. V. , Konopczynski M. R. , Davies D. R. 
Published: September 2008

Abstract
Well performance prediction is a key Petroleum Engineering task. However, large discrepancies between Petroleum Engineering models and reality still frequently occur; despite the continuous increase in the complexity and predictive quality of reservoir models. To-day's field development decisions are still made with a high level of uncertainty in the underlying data and its economic impact.
The degree of data uncertainty is greatest during the exploration stage, but decreases as the reservoir development plan is executed and production data is obtained. Standard, probabilistic workflows have been developed to quantify this uncertainty. These workflows are usually framed by the reservoir scale development plan and end prior to the well's detailed completion design. This is despite the fact that expensive, advanced completions have become common during recent years and the additional investment in such completions can only be justified if it is shown to be paid-back by improved overall project economics which is subject to a significant level of uncertainty.
This paper illustrates the quantification of the long-term benefits of advanced completions using the probabilistic approach. It will be shown how choice of the optimum advanced completion design will reduce the impact of geostatistical uncertainty on the production forecast. Geostatistical realisations of a benchmark reservoir model were generated with a suitable level of data uncertainty. The reservoir was developed by a single horizontal well in a fixed location. The well could be equipped with a variety of completions – an Open Hole with a sand control screen or a perforated pipe, Inflow Control Devices (ICDs) and Interval Control Valves (ICVs).
The probabilistic (P10, P50, P90) oil-recovery distribution was then used to identify the optimum completion design. This completion not only achieved the largest recovery, but also showed the least uncertainty in this value.
A New Compositional Model for Hydraulic Fracturing With Energized Fluids
Authors: Friehauf Kyle , Sharma Mukul M. 
Published: September 2008

Abstract
Traditional fracturing models regard fracturing fluids as a single-component, single-phase fluid. This assumption is clearly incorrect for energized fluids, where phase changes and mass transfer between phases play important roles in controlling fluid rheology, leak-off, and fracture geometry. A model is developed to simulate hydraulic fracturing with energized fluids. Compositional balances allow us to track the changes in phase behavior and fluid properties such as rheology and multi-phase leak-off. An energy balance is implemented in order to consider temperature changes during fracturing. Phase behavior has been taken into account through an equation of state formulation. These compositional and phase behavior effects are coupled with a geo-mechanical model for fracture propagation.
It is shown that phase behavior and leak-off can significantly change the composition and fluid rheology in the fracture. This has a dramatic effect on the fracture geometry. Phase behavior changes are closely coupled to the temperature and pressure changes in the fracture. The temperature, phase behavior, and partitioning of components in the liquid and gas phases have a significant effect on fracture dimensions. For example, shorter and wider fractures can be obtained by foaming an energized fluid. With the model presented, these temperature, pressure, and composition changes can now be accurately modeled and incorporated into the fracture growth and geometry.
Global Challenges Facing the Health, Safety and Environmental (HS&E) Function Within the Oil and Gas Industry
Authors: Bradish Ray , Bui Jonathan , Nunez Yolanda 
Published: September 2008

Abstract
Understanding legislative barriers, communication challenges, and business governance issues are just a slice of what lies ahead for many oil and gas companies choosing to expand their businesses into other areas of the world over the next decade, specifically Russia, China, and India. This paper addresses the challenges of migrating North American and European HS&E management systems, including HS&E personnel, into these domains that historically have not placed HS&E as a core element of business success.
HS&E programs that have demonstrated success in North American markets due to strict government regulations and commitment from corporate management will be faced with new cultures, behavioral challenges, and limited HS&E legislation. In the past, an HS&E professional working in the US or Canada primarily focused on the various elements of HS&E regulatory compliance they may have faced from labor unions, EPA, OSHA, DOT, Transport Canada, etc. This compliance effort seemed insurmountable at times due to the ever-changing bureaucracy from the respective governments in the US and Canada; however, these challenges are miniscule compared to what lies ahead for HS&E professionals supporting global operations. The new breed of HS&E professionals will need to be internationally schooled in many different HS&E country requirements, languages, and customs. Additionally, the largest challenge may be in behavioral transformation relative to understanding risk taking and the mindset of being unbreakable.
How will these challenges be met by companies planning to do the majority of their business in these particular countries? What impact will North American standards have in these countries and how will American and Canadian companies handle resistance to their way of managing HS&E programs abroad? Will organizations like the American Society of Safety Engineers, National Safety Council and the Board of Certified Safety Professionals have any global impact over the next decade? Clearly, these organizations need to have improved global exposure and participation in order to have a positive change in HS&E development. This paper discusses how global oil and gas producers and service companies need to challenge the regulatory bodies of these countries to implement HS&E processes similar to those in North America.
Predicting Hydrate Plug Formation in a Subsea Tieback
Authors: Davies Simon R. , Boxall John A. , Koh Carolyn A. , Sloan E. Dendy , Hemmingsen Pål V. , Kinnari Keijo J. , Xu Zheng-Gang 
Published: September 2008

Abstract
Field data from StatoilHydro on hydrate plug formation in the Tommeliten gas condensate field are compared to predictions of the hydrate growth model (CSMHyK-OLGA) for four typical operating scenarios: 1. steady state operation with failure of inhibitor injection, 2. restart of an uninhibited line, 3. restart of an under-inhibited line and 4. restart of a depressurized line.
Although the CSMHyK model was designed for oil flowlines, the model is able to predict the correct timescale for hydrate plug formation in this gas condensate tieback. The predicted locations of the plugs are often further upstream than observed in the field trials. This is mainly due to the assumption of a "hydrate-oil slip factor" of zero, which forces the hydrate to accumulate where it initially formed. In reality hydrate agglomerates would be carried further downstream before eventually jamming in dips.
Predicting where and when hydrate plugs will form in subsea tiebacks is of increasing importance as the industry strives to manage the risk of plugging in oil and gas flowlines while minimizing the use of costly and environmentally harmful chemicals for hydrate inhibition. The Colorado School of Mines has been developing the CSMHyK model for the past five years in collaboration with the SPT Group and several leading energy companies.
Solving Swelling Clay Issues: Drilling With Expandable Reamers in WBM Reduces Trip Time by 66%, Argentina
Authors: Bazzara Hugo , Biasotti Hugo , Romero Angel , Crovetto Marcelo , Pinheiro Cezar 
Published: September 2008

Abstract
The Chihuido de La Salina field is located in the folded thrust belt of the Neuquén Basin in west-central Argentina, about 200 kilometers northwest of the city Neuquén (Figure 1). The field contains several fault blocks, which produce both oil and gas. Generally, production is controlled by a thrusted anticline, structurally high in the north and relatively low to the south. The most important portion of the field produces oil from the steeply dipping flanks. Efficiently drilling the swelling clay formations of the Neuquén group (Upper Cretaceous), in Chihuido de La Salina field (ChLS), has been a distinctive challenge and is the subject of this paper's analysis and multiple-well case studies.
Slickwater Fracturing - Food for Thought
Authors: Palisch T. T. , Vincent M. C. , Handren P. J. 
Published: September 2008

AbstractThe evolution of fracturing technology has provided the industry with numerous advances, ranging from sophisticated fluid systems, to tip screen out designs, to propagation modeling. Interestingly, these advances have typically been focused on ‘conventional’ designs which utilize a cross-linked fluid system. However, as the development of unconventional (tight gas, shales, coal-bed methane etc) or underpressured reservoirs has increased, so has the demand for innovative hydraulic fracture designs. The most recent of these design changes has been the popular method of placing proppant with slickwater, linear gel or hybrid treatments.Although our industry has significant expertise in fracture design, most of our experience has been in conventional cross-linked fluid systems. However, there are many aspects of cross-linked fluid design that either do not apply to slickwater treatments, or in some cases are exactly opposite.This paper will begin by reviewing the motivation, benefits and concerns with slickwater fracturing, and discuss why this seemingly ‘old’ method has regained popularity over conventional cross-linked designs in many reservoirs. In addition, the authors will detail some of the important theories related to slickwater fracturing, including fracture width and complexity, proppant transport and settling, and conductivity requirements. In each case, emphasis will be placed on the different strategy that must be employed compared to cross-linked fluid designs, and highlight the mistakes or misunderstandings that are frequently made.Where appropriate, lab testing, field measurements, reference material and other resources are presented to support the observations made by the authors. This paper will serve as a resource to any engineer or technician who is designing/pumping slickwater fracs, or who is considering this technology for potential application. By applying the concepts presented in this paper, engineers will be able to appropriately evaluate the potential benefits of using this technique in their completions, as well as draw on the experiences of others to take full advantage of this technology.
Improved Recovery in Gas-Condensate Reservoirs Considering Compositional Variations
Authors: Shi Chunmei , Horne Roland N. 
Published: September 2008

Abstract
The objective of this work was to develop a methodology to increase the productivity of gas/condensate from gas-condensate reservoirs. Presently, gas-condensate reservoirs experience reductions in productivity by as much as a factor of 10 due to the dropout of liquid close to the wellbore. The liquid dropout blocks the flow of gas to the well and lowers the overall energy output by a very substantial degree. The combination of condensate phase behavior and rock relative permeability results in a composition change of the reservoir fluid, as heavier components separate into the dropped-out liquid while the flowing gas phase becomes lighter in composition. This effect has been sparsely recognized in the literature, although there is clear evidence of it in field observations. This work quantified the effect, developed a scientific understanding of the phenomena, and used the results to investigate ways to enhance the productivity by controlling the liquid composition that drops out close to the well. By optimizing the producing pressure strategy, it should be possible to cause a lighter liquid to be condensed in the reservoir, after which the productivity loss would be more easily remedied.
The research made use of experimental measurements of gas-condensate flow, as well as compositional numerical simulations. Different strategies have been compared, and the optimum producing sequences are suggested for maximum condensate recovery. Results show that composition varies significantly as a function of fluid phase behavior and producing sequence; condensate recovery can be improved with proper producing strategy, and productivity loss can be reduced by changing the producing sequence.
This study can be used to determine the optimum producing strategy when the well is brought into production and reduce the productivity loss caused by the condensate banking effect.
CO2 Injection for Enhanced Gas Recovery and Geological Storage of CO2 in the Long Coulee Glauconite F Pool, Alberta
Authors: Pooladi-Darvish Mehran , Hong Huifang , Theys Sophie , Stocker Rudi , Bachu Stefan , Dashtgard Shahin 
Published: September 2008

Abstract
Impure CO2 containing less than 2% H2S has been injected since 2002 into the depleted Long Coulee Glauconite F gas Pool in southeastern Alberta. Breakthrough was observed within one to three years in producing wells, leading to their abandonment. Simulation studies reported in this paper indicate that additional gas was recovered as a result of CO2 injection. An interesting observation at the breakthrough wells was that the CO2 broke through ahead of the H2S. The partitioning of the H2S and CO2 as they flow through the reservoir was studied in detail. One objective of the reported work is examination of interactions of the injected gas with the in-situ fluids and the displacement of the in-situ gas by the injection gas, for better understanding of the mechanisms involved in enhanced-gas recovery. Another objective of the work is to study factors that affect the spread of the injected gas in a depleted oil and gas reservoir and its implications with respected to CO2 geological storage. The results of this study indicate that at low pressures, the injected gas occupies a large reservoir volume and exhibits little density difference with the in-situ fluids, leading to rapid spread of the injected gas and early breakthrough. Also, it was found that in the case of Long Coulee Glauconite F gas Pool the well-spacing used for production did not allow a detailed geological characterization that was required for accurate prediction of breakthrough as a result of gas-gas displacement. Simulation studies, together with displacement experiments in the laboratory reported elsewhere, confirmed that the preferential solubility of H2S in the reservoir water led to stripping of the H2S at the leading gas front and it delayed its breakthrough relative to that of CO2. The implications of such chromatographic partitioning of H2S and CO2 in geological storage of impure CO2 streams are discussed.
Modeling Reservoir Temperature Transients and Matching to Permanent Downhole Gauge Data for Reservoir Parameter Estimation
Authors: Duru Obinna , Horne Roland N. 
Published: September 2008

Abstract
Permanent downhole gauges (PDGs) provide a continuous source of downhole pressure, temperature and sometimes rate data. Until recently, the measured temperature data have been largely ignored. However, a close observation of the temperature measurements reveals that the temperature responds to changes in flow rate and pressure, which implies that the temperature data may be a source of reservoir information.
In this work, the Alternating Conditional Expectations (ACE) technique was applied to temperature and flow rate signals from PDGs to establish the existence of a functional relationship between them. Then, performing energy, mass and momentum balances, reservoir temperature transient models were developed for flow of single- and multiphase fluids, as functions of formation parameters, fluid properties, and changes in rate and pressure. The pressure fields in oil and gas bearing formations are usually transient. This gives rise to pressure-temperature effects appearing as temperature changes in the porous medium when the pressure field changes. The magnitudes of these effects depend on the properties of the formation, flow geometry, time and other factors and result in a reservoir temperature distribution that is changing in both space and time. Therefore, in this study, reservoir thermometric effects were modeled as convective, conductive and transient phenomena with consideration for time and space dependencies. This mechanistic model included the Joule-Thomson effects due to fluid compressibility, and viscous dissipation in the reservoir during fluid flow in accounting for the reservoir temperature dependence on changing pressure/flowrate fields.
Numerical solution schemes as well as the semianalytical scheme – Operator Splitting and Time Stepping (OSATS) were used to solve the models, and the solutions closely reproduced the temperature profiles seen in real measured data. By matching the models to different temperature transient histories obtained from PDGs, reservoir parameters namely porosity and saturation and fluid Joule-Thomson coefficient could be estimated. Hence the normally unused temperature data record can be used to estimate reservoir parameters not usually available from conventional well test analysis. Analysis of temperature may also provide a less expensive substitute for downhole flow rate measurement.
A Multiresolution Analysis of the Relationship between Spatial Distribution of Reservoir Parameters and Time Distribution of Data Measurements
Authors: Awotunde Abeeb A. , Horne Roland N. 
Published: September 2008

Abstract
An important issue in reservoir parameter estimation is to develop computationally efficient and reliable nonlinear regression procedures. We present a multiresolution wavelet approach to estimate spatial distribution of reservoir parameters, by performing the nonlinear least squares procedure in the wavelet domains of both time and space. Wavelet transforms have the ability to reveal important events in any signal or image. Thus we transformed both the model space and the data time into spatial wavelet and time wavelet domains and used a thresholding to select a subset of wavelet coefficients from each of the transformed domains. These subsets were subsequently used in the nonlinear regression procedure to estimate the appropriate subset of reservoir parameters. The appropriate subset is not only smaller and therefore more efficient computationally, the problem is also reduced to the consideration of only the important components of the measured data and only the part of the reservoir description that depends on them.
We applied the procedure to a radially composite reservoir system to demonstrate the reliability of the approach. The inverse problem was solved to estimate the distributed permeability values by performing the nonlinear least square regression in the wavelet domains (time and space).
Results obtained were compared to those obtained from the conventional nonlinear regression approach. The time-space wavelet approach proves to be more efficient computationally compared to the conventional approach. By reducing the dimensions of the model and data spaces the model stabilizes the algorithm and gives faster convergence. Significantly, the approach reveals the true number of reservoir parameters that can be appropriately estimated from a given data set.
The approach provides a good means to integrate different data properly while avoiding the inclusion of irrelevant data during nonlinear regression. The procedure also reduces the number of iterations needed for convergence.