bluuebunny/crossref_metadata_2025_split huggingface dataset:
Rapid Assessment of Potential Recovery Factor: A New Correlation Demonstrated on UK and USA Fields
Authors: Wickens Laurence M , Kelly Roy 
Published: February 2011

Abstract
A new correlation between recovery factor and a reservoir complexity index has been developed and is demonstrated on UK and USA fields.
The correlation allows rapid assessment of the potential recovery performance of reservoirs. It also enables the extent of reservoir underperformance to be assessed. The applications of this approach extend from a rapid evaluation of a field when time is limited to a comparison of fields for benchmarking purposes. The correlation includes a number of key parameters such as in-situ viscosity, structural compartmentalisation, reservoir heterogeneity and may be easily expanded to include other parameters as necessary.
Results are presented for a large number of identified UK and USA fields with a wide range of complexity and a variety of reservoir and fluid types. This information helps structure comparison of specific fields with others and facilitates the development of analogues. The data shows a clear upper limit to reservoir performance for a given reservoir complexity.
Detailed information on the fields in the form of a complexity index is published, enabling others to use and further develop the approach and add their own data.
The approach extends aspects of a previously published complexity index. It is based on sound reservoir engineering parameters that minimize the problems associated with qualitative judgments of parameter values.
Inversion of Surface Subsidence Data to Quantify Reservoir Compartmentalization: A Field Study
Authors: Fokker P. A. , Visser K. , Peters E. , Kunakbayeva G. , Muntendam-Bos A. G. 
Published: February 2011

Abstract
The Roswinkel gas field in the northeastern part of the Netherlands has been in production between 1980 and 2005. Located at about 2100 m depth, it is a severely faulted anticlinal structure, constituting up to 30 reservoir compartments. Due to the complicated nature of this field, there are large uncertainties in both the fault transmissibilities and the strength of the connected aquifer. Consequently, there is a possibility of undepleted compartments in the reservoir.
Pressure depletion due to gas production results in compaction of the reservoir sandstones leading to surface subsidence. The gas production in Roswinkel has induced subsidence of approximately 17 cm above the centre of the field. The subsidence at any point on the surface is a result of compaction over a large area within the reservoir.
We estimated the compaction in the reservoir using subsidence data in order to reduce the uncertainties in fault transmissibility and aquifer connection. We employed a previously developed Bayesian inversion method in which prior knowledge is combined with observations. The prior knowledge on the compaction and the associated uncertainties were generated by Monte Carlo simulations of the reservoir in which the fault transmissibilities were varied. In the mean time the geological reality was maintained and the production history was honored. The average prior compaction field is a relatively smooth field extending well into the aquifer, with a typical uncertainty of 40%.
Our inversion results show a reservoir in which certain large faults are dividing the reservoir in compartments containing different pressure histories. Furthermore, the aquifer activity appeared to be much weaker than the average prior knowledge suggested. The posterior uncertainty of the compaction levels was reduced to about 10%. Our study demonstrates that a carefully executed inversion exercise can considerably reduce uncertainties, thus giving scope for the identification of undepleted compartments in the reservoir.
Sand Prediction: A Practical Finite-Element 3D Approach for Real Field Applications
Authors: Volonté G. , Scarfato F. , Brignoli M. 
Published: February 2011

Abstract
Sand production is a critical issue in Oil & Gas industry. During the production of a well, sand production may have negative consequences such as risk of well failure, erosion of pipelines and surface facilities and need for sand separation and disposal. Knowing the conditions for the onset of sand production allows optimizing sand free production and, eventually, avoiding or delaying the use of sand control methods.
The aim of this work is to establish a reliable workflow for the estimation of the conditions for sand production, in real field cases, by means of Finite Element Modelling. With this respect, the fundamental requirement is to set-up a 3D coupled model that can be easily adjusted the most complex conditions (e.g. stress anisotropy, deviated wells, complex perforations patterns).
The most suitable geometries and associated meshing strategies to describe the wellbore, the perforation tunnels and the surrounding formation are analyzed. The drilling and completion phases were also simulated to compute the correct stress distribution before the production. Fluid flow and rock deformation are simulated in a fully coupled way to investigate accurately the effect of drawdown.
Shear failure of reservoir rock, considered as an elasto-plastic medium, is the main sand production mechanisms analyzed and the damage of the rock around the perforations is evaluated by analyzing the distribution of the equivalent plastic strain.
A real field case is simulated and the results of the Finite Element model are consistent with the ones obtained by means of an analytical model and with field observations. Moreover, this numerical approach allows quantifying the spatial distribution and the severity of the damage of the rock around the perforations, facts that are either oversimplified or not considered at all in analytical models.
For future applications, this model can be straightforwardly extended to more complex conditions and can also be improved to provide volumetric sand prediction.
Enhanced Seismic Velocity Processing to Improve 3D Geopressure Evaluation
Authors: Cibin Patrizia , Della Martera Mauro , Andreoletti Clara , Bellucci Niccolò 
Published: February 2011

Abstract
Geopressure evaluations are key considerations for successful well planning and drilling. The necessity to satisfy the world needs of oil & gas presses Oil Companies to drill in conditions that are getting harder and harder in terms of geopressure environment. The pore pressure prediction accuracy has a large impact on the cost of a project and is especially critical for drilling high-temperature/high-pressure (HP/HT) wells where there is a small margin between pore and fracture pressures. This paper outlines the most accurate methodologies to estimate seismic velocities to be used for the pore pressure prediction.
In exploration, pore pressure prediction is critical for the evaluation of vertical and lateral sealing, the estimation of maximum possible column of hydrocarbons in place, and consequently to rank the prospects and evaluate the economics. As far as concerns drilling, the geopressure information is important to define the best well design in order to reduce costs, NPT (Not Productive Time), wellbore stability, sand production and reservoir damages.
Generally, in complex and deep areas, conventional velocity fields derived from seismic time processing are often not accurate enough to make a correct pore pressure prediction. For this reason, several methods have been developed trying to obtain more appropriate velocity fields. In this paper we compare some of them, mainly CVA (Continuous Velocity Analysis) calculated in the time domain versus Grid Tomography, applied in the depth domain.
In particular, Eni proprietary software based on reflection tomography, able to integrate geological information in the Grid Tomography loop, has been successfully applied in North Africa, where the exploration goal is to reach deep HP/HT targets. Besides, in that region, strong pressure anomalies and pressure compartments are frequently present in the shallower layers, due to compaction disequilibrium and vertical pressure transfer along faults or through windows in salt layer.
These phenomena have created serious problems during drilling operations in the past and a good geopressure prediction can considerably reduce drilling costs and risks. The application of the proposed methodology to build the seismic velocity field has been important both in defining more detailed pore/over pressure volumes and structural models by an iterative pre stack depth migration workflow.
Potential Upside Reserves of Shallow Gas Discovered Within the Early Triassic Mount Goodwin Sub-Group and the Early Permian Torrens and Fossil Head Formations in the Blacktip Gas Field, Bonaparte Basin, Australia
Authors: Wheller Dave , Caudullo Andrea 
Published: February 2011

Abstract
The Blacktip Gas Field is located offshore in the southern Bonaparte Basin, Australia. The main reservoirs are the Early Permian Keyling and Treachery Formations. The field supplies gas to the Northern Territory utility Power and Water Corporation from two deviated gas production wells via an unmanned well-head platform to shore at Yelcherr near Wadeye in the Northern Territory. The field will deliver gas to the Northern Territory's Power and Water Corporation over a period of 25 years.
One of the potential upsides of the gas field is the shallow and previously overlooked Early Triassic Mount Goodwin Sub-Group sandstones and also the Early Permian Torrens and Fossil Head Formations. Eni successfully acquired more data from the drilling of the development wells over these sections, with the objective being to fully assess minor gas shows observed in the original Blacktip-1 discovery well.
The Mount Goodwin Sub-Group Sandstones, Torrens Formation and Fossil Head Formation are a thick sequence of inter-bedded shale, siltstone and very fine sandstones. The intervals are thinly bedded, and this makes conventional wireline difficult to interpret. Acquiring a wireline image log and performing a petrophysical thin-bed analysis has helped define the net sandstone thickness and net pay thickness of these formations. Performing geochemical analyses on mud gas samples collected in isotubes has helped to characterise the gas composition throughout the formations. In addition, the identification of moveable gas and verification of the extent of the gas columns has been achieved through the acquisition of formation pressure points and bottom- hole samples by Modular Formation Dynamic Tester (MDT). The conclusion is that from review of recently acquired data the Mount Goodwin Sub-Group Sandstone, Torrens Formation and Fossil Head Formations show good potential for future development in the Blacktip Field. A comparison between conventional log analysis and thin bed analysis is also discussed, with estimates of net sand and net pay thickness contrasted.
Blacktip Field is 100% owned and operated by Eni Australia.
A Comparison of Hydraulic Fracture Modeling With Downhole and Surface Microseismic Data in a Stacked Fluvial Pay System
Authors: Mohammad Nur Azlinda , Miskimins Jennifer L. 
Published: February 2011

Abstract
This paper presents a study that combines and compares the results of hydraulic fracture mapping and modeling using both downhole and surface microseismic arrays. There were three objectives for the study including 1) developing detailed posttreatment models of hydraulic fracturing treatments in the subject well, Well D1, which was monitored with downhole microseismic tools; 2) developing detailed post-treatment models of the hydraulic fracturing treatments in the subject well, Well S1, which was monitored with surface microseismic tools; and 3) determining the match characteristics of the downhole and surface microseismic data to hydraulic fracture models developed for both Wells D1 and S1.
Input data for this project were obtained from two wells in the Greater Natural Buttes field, Uinta basin, Utah. Ten fracture models were built using five stages each from the two subject wells, Wells D1 and S1, and detailed pressure matches were made. Comparisons of the match characteristics from the multiple inputs were then developed. The hydraulic fracture stimulation models were graphically integrated with the microseismic events using visualization software. This software allowed the final model-simulated fracture geometries to be plotted along with the microseismic events in three-dimensional space thus allowing the viewer to see a full integration of data in a stacked fluvial pay system.
Results from the integration process show good agreement in geometries and depth for most stages in the downhole-monitored well, whereas comparisons of surface microseismic mapping measurements with the simulated fracture geometries yielded variable results. When combined with additional inputs, such as geologic models, the integration methodology used in this project provides an excellent tool for hydraulic fracture modeling and reservoir management in stacked pay systems.
Role of Stress Reorientation in the Success of Refracture Treatments in Tight Gas Sands
Authors: Roussel Nicolas P. , Sharma Mukul M. 
Published: February 2011

Abstract
The redistribution of stresses around a fractured vertical well has two sources: (a) opening of propped fracture (mechanical effects) and (b) production or injection of fluids in the reservoir (poroelastic effects). In this paper, the coupling of both phenomena was numerically modeled to quantify the extent of stress reorientation around fractured production wells. The results have been compared to field data from the Codell tight gas formation and analyzed for their impact on refracturing operations.
For previously fractured wells, a secondary fracture may be initiated perpendicular to the first fracture if a stress reversal region is present. Altered-stress refracturing makes it possible to access zones of the reservoirs that are less depleted, thus increasing well production and reserves.
The results of our model quantitatively agree with previous tiltmeter measurements, confirming the existence of refracture reorientation in the Codell formation. The performance of refracturing treatments has been observed to be highly variable in the Wattenberg field (Colorado) with some wells underperforming while others are restored to initial production rates. Historical production from neighboring wells and initial fracture performance were shown to impact the potential benefits from refracturing predicted by the numerical model.
This paper introduces a three-dimensional model coupling mechanical and poroelastic stress reorientation used to interpret tiltmeter measurements and historical production in the Codell tight gas formation. Guidelines are drawn from the Wattenberg field case study that allow an operator to (a) select candidate wells, (b) choose the timing of the refracture operation in the life of the well, and (c) evaluate the potential increase in well production after refracturing.
Enhancing Sand Screen Reliability: An Innovative, Adaptive Approach
Authors: Yeh C. S. , Moffett T. J. , Barry M. D , Hecker M. T. , Howell D. A. , Green A. , Gillespie G. A , Hall C. A. , McNamee S. 
Published: February 2011

Abstract
Sand control reliability becomes increasingly important when combining challenging well conditions with the expectations of high flow rates, reduced well counts, and rising costs. Sand screens, the final sand control barrier, have been a critical element to assure long term well reliability. Any screen damage along the well may allow sand ingress and adversely impact the overall production. Preventive (flux limitations) and reactive (choking) methods can reduce the risk of downhole screen damage under complex producing environments, but these methods are unable to mitigate all risk. A step change in screen design to enhance sand screen reliability is needed which can also maintain simple and economic completions.
MazeFlo™ technology, currently under development, was invented to be adaptive to downhole uncertainties and to self-mitigate screen damage. The technology utilizes a redundant sand screen and compartment maze to constrain local sand ingress caused by screen damage without interrupting well production. A prototype screen has been designed and fabricated.
A series of hydraulic and mechanical tests were conducted to validate the prototype design. Both compartment and redundant screens are qualified in flow friction, erosion resistance, and mechanical integrity. A field trial has been designed to demonstrate the screen installation, downhole self-mitigating capability, and sustained production. Operationally, the innovative and robust screen design will appear and run similar to conventional screens.
Successful prototype development will lead to a 2 3/8-in MazeFlo screen ready for use in remedial workover applications. The design philosophy and qualification process are being extended to larger screen sizes for broader applications. The adaptive approach implemented in this novel sand screen establishes a new milestone to enhance sand screen reliability. The collaboration between operator and service supplier enables effective commercialization of innovative technology for the next generation of sand control completions.
Study of Unusual Responses from Multiple Resistivity Tools in the Bossier Formation of the Haynesville Shale Play
Authors: Corley Bill , Garcia Alex , Maurer Hans-Martin , Rabinovich Michael B. , Zhou Zhiqiang , DuBois Patricia , Shaw Nolan 
Published: February 2011

Abstract
Over the years reports have been made of anomalous wireline induction log responses in some shale formations. Anderson (Anderson, 2000) suggested an extremely large dielectric effect as an explanation. As shale formations such as the Woodford, Bossier, and Haynesville plays have gained attention as reservoir rocks, it is important that we understand the reasons for these anomalies.
This paper examines resistivity wireline logs run in the Bossier Shale, Louisiana with several instruments based on different physical principles which indicate that a large dielectric effect cannot be the only cause of the anomalous responses.
The following logs were acquired:
Array Induction log, frequency 10 kHz to 150 kHz
Multi-Laterolog, frequency 30 Hz to 200 Hz
Dielectric log, frequency 200 MHz
Multi-Component Induction log, frequency 20 kHz to 220 kHz
Accurate tool responses in ‘typical’ shale above the Bossier formation all provide evidence that the tools are functioning properly. A pure dielectric effect would linearly increase with frequency (smallest for the low frequencies and largest for the high frequencies). The observed behavior indicates that the low- and medium-frequency tools show similar anomalous response, while the high-frequency dielectric tool is unaffected.
The multi-component induction response, however, shows a strong azimuthal effect where the horizontal ZZ component is always affected. One vertical component (XX or YY) is also affected, while the other vertical component appears normal. The affected vertical component alternates as the tool rotates.
New Inflow Control Device Provides Solid-Liner Functionality Throughout Installation and Fluid Loss Control During Completion
Authors: Infra Morry , Coronado Martin P. , Woudwijk Roy , Al-Mumen Adib A. , Al-Baggal Zaki A. 
Published: February 2011

Abstract
Openhole horizontal completions in consolidated formations have been commonplace for a number of years. This type of completion has been very successful due to the relative simplicity of the completion design and ability to segment the horizontal production interval by using openhole hydrostatic-set packers. Using inflow control devices (ICDs) in this completion design allows a uniform inflow across the entire horizontal wellbore, which mitigates early water or gas coning into the wellbore.
A newly designed ICD has been developed and field-trialed successfully that mitigates the need for an inner string during installation, allowing circulation through the liner while running in the hole as well as hydraulic setting of the openhole packers before pulling out of the hole with the workstring. This also provides an improved well control condition. A temporary valve system has been incorporated into the ICD design that provides pressure integrity in the liner until after the upper completion has been installed. Once the upper completion is in place, the valves are triggered hydraulically with applied pressure in the production tubing and opened once the differential pressure is removed, allowing the ICD to be reconfigured into the production mode. Once the valves have been opened the ICD performs normally for the operational life of the well.
This completion technology also provides the added benefit of isolating the upper wellbore from the reservoir until after the upper completion is installed. This potentially prevents unwanted and costly fluid losses into the formation before the well is put on production.
This paper will describe the new ICD design technology developed for the application and review initial case history well installations in Saudi Arabia.
A Process to Evaluate Unconventional Resources
Authors: Chan Phillip , Etherington John R. , Aguilera Roberto 
Published: February 2011

Abstract
It is the intention of the SPE/WPC/AAPG/SPEE Petroleum Resources Management System (PRMS) to provide a consistent approach to estimating petroleum quantities, evaluating development projects, and presenting results within a comprehensive classification framework. The reserves and resources definitions and application guidelines are designed to be applicable to both conventional and unconventional petroleum accumulations, regardless of their in-place characteristics, the extraction method applied, or the degree of processing required to yield a marketable product.
The fact that unconventional resources are usually pervasive throughout a large area and are not significantly affected by hydrodynamic influences may require different approaches in evaluation. Assessments may include an increased sampling density to define uncertainty of in-place volumes, the variations in quality of reservoir, and hydrocarbons and their detailed spatial distribution for the design of specialized extraction methods.
This paper summarizes the special problems in the estimation and evaluation of several resource types ranging from shale gas to bitumen. The material is largely drawn from the soon to be published SPE Application Guidelines to the PRMS, supplemented with illustrations from actual field examples.
The rapidly advancing exploitation of unconventional resources has opened up many development opportunities, especially in North America. Shale gas and bitumen have already caused major impact on energy supply. We anticipate these opportunities will expand rapidly throughout the world. Achieving a better understanding of the special problems in unconventional resources evaluation will help us build on PRMS to develop a more consistent approach to classification and categorization, accounting for unique project risks and uncertainties.