bluuebunny/crossref_metadata_2025_split huggingface dataset:
Geo-engineering and Economic Assessment of a Potential Carbon Capture and Storage Site in Southeast Queensland, Australia
Authors: Cinar Y. , Neal P. R. , Allinson W. G. , Sayers J. 
Published: December 2007

Abstract
This paper presents geo-engineering and economic sensitivity analyses and assessments of the Wunger Ridge flank Carbon Capture and Storage (CCS) site.
A numerical reservoir simulation examines injection rates ranging from 0.5 to 1.5 million tonnes of CO2/year. Primary factors affecting the ability to inject CO2 include permeability, formation fracture gradient, and multiphase flow functions. Secondary factors include the solubility of CO2 in the formation brine, injection well location with respect to the flow barriers/low-permeability aquifers, model geometry including faults, grid size and refinement, and injection well type. Less significant factors include hydrodynamic effects.
The economics are assessed using an internally developed techno-economic model. The model optimises the CO2 injection cost based on geo-engineering data and recent equipment costs. The overall costs depend on the initial costs of CO2 capture and on source-to-sink distances and their associated pipeline costs. Secondary cost variations are highly dependant on fracture gradient, permeability and CO2 injection rates. Depending on the injection characteristics, the specific cost of CO2 avoided is between A$30 and A$44 per tonne.
Safety Training for the Workforce via E-Learning
Authors: Wheeler C. , Charusalaipong P. 
Published: December 2007

Abstract
Oil and Gas Exploration and Production (E & P) work activity has inherent hazards in its nature of operations. Many previous catastrophic incidents have left a mark in the public’s memory. In recent years, younger and inexperienced workers have joined the industry, which has not made it any easier to curve-down the trends of incidents and the related consequences, e.g. personnel injury, fatality, asset damages and environmental impacts.
As an operator in the E & P business, it is our duty to ensure workforce competency, particularly for workers going offshore. Specific Safety Training plays a key role in the delivery of the many mandatory safety topics. But how best to make subject delivery understandable, interesting, efficient and even cost effective?
Traditional Classroom / Safety Trainer techniques have been used over the years but difficulties can be experienced when encouraging (as compared to enforcing) existing staff to attend mandatory refresher training and stimulating the right atmosphere for new hires. It was time to look at different ways to approach the problem.
Various options were considered but the option that appeared most suitable for our needs was E-learning.
The purpose of this document therefore, is to provide a more detailed understanding of the Safety E-learning option, the applications, commercial considerations and problems involved with its implementation.
Combining Testing-by-Difference, Geochemical Fingerprinting, and Data-Driven Models: An Integrated Solution to Production Allocation in a Long Subsea Tieback
Authors: Dolle Norbert , Gelin Francois , Tendo Fidelis , Goh Keat-Choon , Overschee Peter van 
Published: December 2007

Abstract
Well-by-well production allocation in a subsea production cluster is often very challenging without a separate test line. This is recognized in field development plans and can be mitigated by installing subsea and downhole measurement devices, such as downhole gauges and/or flowmeters. Long-term reliability of these devices, however, remains an issue. In the subsea cluster described by this paper, most of the measurement equipment indeed failed or became erroneous within limited timeframe after installation in 2002. As reliable information became scarcer, the uncertainties in the production allocation increased with a direct negative impact on field management.
The solution that was implemented in this Shell UK Limited operated North Sea cluster consists of an integrated application of periodic testing-by-difference and data-driven modelling. Data-driven models have the potential to act as continuous virtual flow meters, relating pressure and temperature changes per well to variations in the well production rates. Data-driven models for real-time monitoring of well-by-well oil and gas production have been widely deployed in the Shell Group in the form of the FieldWare Production Universe (FWPU) application. For these data driven models to be sufficiently accurate, they need to be calibrated with actual production information. In a subsea environment without testing facilities, this information can be derived from testing the wells by-difference and also from short and medium term production data. This paper shows that fairly satisfactory production rate estimates can be obtained with FWPU, even when the subsea tieback to the production and export facilities is more than 50 km long.
Accuracy of the production rates derived from testing-by-difference can be impacted by interference between the wells, especially with a long tieback. Carefully designing and implementing the test and quality checking the derived rates with well flow models can ensure the usefulness of the data. In this paper we will also show that geochemical fingerprinting of fluid samples taken during the test provides valuable information about the quality of the estimates and the behaviour of the fluids in the flowline.
The aim of this paper is not to justify the omission of physical measurement devices or well testing facilities in challenging subsea environments, but to promote the described techniques as valuable additions and possible contingencies.
Ormen Lange Subsea Condition and Leakage Monitoring
Authors: Abrahamsen Jens , Haugen Svein , Bertmand Trond Benny , Lie Gunnar Hannibal 
Published: December 2007

Abstract
With the Ormen Lange development, Norsk Hydros subsea solutions are taking technological developments on the Norwegian continental shelf a significant step ahead. Nothing will be visible on the surface when the enormous gas field comes onstream in 2007. High pressure, large water depth and distant location called for a new way of thinking in many ways. This paper will present the leakage and condition monitoring system developed to ensure safe and pollution free operation of the two templates at 850 meters of water depth. Hydro and Naxys Naval Technology started already back in 2000 the development of a new type of subsea monitoring system based on technology originally developed for naval warefare and surveillance. After successful testing on the subsea processing plant, Troll Pilot in 2001, the system was further developed and qualified. On the Ormen Lange Templates one centrally positioned module containing an array of acoustic sensors monitors the complete 44 × 33-m template. The system provides location and magnitude of any leak, structural vibration or valve malfunction on the template.
A New Method of Evaluating the Productivity Index for Nonlinear Flows
Authors: Aulisia E. , Ibragimov A. , Valkó P. P. , Walton J. R. 
Published: December 2007

Abstract
This paper addresses the effects of non-linear, non-Darcy flows in reservoir on the value of the productivity index. The productivity index (PI) of the well draining a reservoir with no flux on the exterior boundaries is defined as the ratio between the production rate and the pressure drawdown. Experience shows that during the dynamical process of hydrocarbon recovery this ratio stabilizes to some constant value, which, in general, is a non-linear function of both the pressure drawdown and the production rate.
The linear (Darcy) case is well understood, and excellent approximate formulae are available to compute the PI for various well-reservoir geometries. These formulae are generally obtained through a semi-analytical solution of the transient problem. To handle the more realistic non-linear situation, the current practice is to solve first the nonlinear problem many times for different values of production rate, and then to add some ad-hoc corrective parameter(s) in the linear formulae in order to reproduce the non-linear nature of the flow.
Our approach, based on recent progress in the modeling of transient Forchheimer flows, uses partly non-numerical techniques to evaluate the productivity index. It provides, for a wide class of reservoir geometries, an accurate enough approximate algebraic relation between the PI for the nonlinear Darcy-Forchheimer flows and the PI for the Darcy flows.
We show that the solution of the original problem can be obtained by applying direct variational methods, which are computationally less expensive than the grid based techniques. In addition, by using the existing and newly developed approaches in the theory of symmetrization, alternative "non-analytical" algorithms are presented to assist optimal well design, without repeatedly solving numerically the reservoir simulation problem.
The approach will be demonstrated on practical well optimization problems.
Using Field Results To Guide Proppant Selection in the Pinedale Anticline
Authors: Vincent M. C. , Huckabee Paul 
Published: December 2007

Abstract
A field trial was conducted in the Pinedale Anticline of Wyoming to compare well productivity as a function of proppant type and geologic interval. This study compares production from 446 fracture treatments in 30 new wells completed by Shell between September 2001 and September 2004. Great effort was put into the design of the field trial, the collection of data in a systematic method, and careful analyses of the data. Data and analyses from this field trial have been presented in SPE 96559, SPE 100574, and SPE 106151. This current paper summarizes the techniques utilized in each paper to analyze the field results, compares the relative confidence in conclusions reached with each technique, and highlights lessons learned in the process of conducting and evaluating this field trial.
In this field, the authors conclude with greater than 99.9% certainty that production is affected by proppant selection. Even in this extremely tight formation (∼0.002 mD or 2 microdarcies) the fractures remain conductivity-limited, and productivity is greatly influenced by proppant selection. The extremely high level of statistical significance has been achieved by the following:
A sizeable population of wells were completed by a single operator during a short time interval; Drilling, completion, and fracturing stimulation variables were minimized; Proppant types were compared in the same geologic intervals from wells in a small geographic area; Production logs were conducted and analyzed in a systematic fashion, calibrated and corrected to an equivalent logging date; Production data were analyzed with and without normalization to log-derived petrophysical information; Prior to initiation of the trial, 22 geologic subintervals and four separate study areas were defined to investigate subgroups of data in the most homogenous conditions; Statistical analyses were performed on the full dataset, with smaller subgroups of data, and with numerous normalization techniques to determine whether random reservoir variation could account for the results.
The compilation of these results should be of value to those considering a field trial in a complex geologic setting or comparing the results of propped fracture stimulated wells. Optimizing proppant selection has been shown to significantly increase the economic potential of tight gas wells.
Optimal Region Delineation in a Reservoir for Efficient History Matching
Authors: Yadav S. , Heim R. , Bryant S. , Sinha Rohit , May Ed 
Published: December 2007

Abstract
In a large field, history matching is generally performed first at the field level, then at regional level, followed by individual well history matching. This paper presents a novel methodology for delineating multiple reservoir regions for the purpose of efficient history matching.
Ideally the regions in a reservoir should be independent in terms of their effect on the objective function. Otherwise perturbing one variable to improve the match in a particular region may adversely affect the match in other regions. Full independence of regions within a reservoir is not possible unless they are separated by zero permeability streaks or sealing faults. The proposed approach isolates least correlated and most sensitive regions within a reservoir. The least correlation criterion ensures that there is a minimal effect of changing one parameter in one region, to the responses from the other regions. Further, since the regions are least correlated with each other, each region can be history matched independently and simultaneously. The most sensitive criterion increases the effectiveness of history matching.
In order to delineate reservoir regions that can be history matched independently, principal component analysis (PCA) of the Hessian matrix has been done. The Hessian matrix summarizes the sensitivity of the objective function at a given step of the history matching, to permeability at the grid block level. The eigenvectors obtained during the PCA are suitably scaled and appropriate grid block volume cut-offs are defined such that the resultant regions are neither too large (which increases interactions between regions) nor too small (implying ineffective history matching).
The proposed technique has been successfully tested in a fluvial depositional environment. In order to test the robustness of the approach, zero transmissibility faults were deliberately created in the simulation study. The approach could successfully delineate the regions across the faults.
Reservoir Management Aspects of the Rejuvenation of the Forties Field, UKCS
Authors: Vaughan Owen , Jones Richard , Plahn Sheldon 
Published: December 2007

Abstract
When Apache Corporation bought the Forties field in 2003, the field had produced about 2.5 billion barrels of oil from an original oil in place of nearly 5 billion barrels. Historically, cumulative production from some wells had been more than 80 million barrels. By contrast, the remaining drilling targets in 2003 were much smaller, as well as being distributed across the entire field (18 km by 10 km) and reservoir section. In addition, the facilities were nearly 30 years old and designed for fluid rates very different from those current in 2003.
Since 2003, Apache has rejuvenated the field through a combination of facilities improvements, workovers, and drilling new wells. Management of the Forties reservoir during this rejuvenation has had to take into account the challenges of accessing small, widely distributed targets and the constraints of facilities projects being run in parallel.
Initially, 4D seismic was used as the main tool to identify drilling locations. This was an appropriate technique to identify the larger targets but became less certain as thinner oil columns and deeper parts of the section were targeted. During this initial phase of drilling a fine-scale reservoir model was constructed and is now used with streamline simulation as a tool to assess targets and optimise the waterflood. The installation of multiphase well testing equipment and a widespread use of electric submersible pumps with permanent downhole gauges have provided new insights into reservoir performance. Sand control techniques have been introduced in order to manage the potential for sand production. Understanding and working with the interdependency of reservoir management, drilling, and facilities has been essential throughout the process.
The combination of 4D seismic and simulation techniques which has guided the rejuvenation of Forties are presented, along with the interactions with facility-related projects.
Maximising ESP Uptime in Forties Field—Introducing Successful Frac Packs to the North Sea
Authors: Norris M. R. , Plahn S. , Lowton D. , Tsangueu B. 
Published: December 2007

Abstract
This paper demonstrates, via a comprehensively described recent case history, the transfer of established completion technology into the North Sea. Further, in performing the process the technique has been successfully extended beyond its normal criteria of application.
Today artificial lift in the Forties Field is provided by a large number of electric submersible pumps (ESPs) lifting from shale inter-bedded sandstone sequences. Overall production is affected by the achieved ESP run-life in a field where sand-face failure is not uncommon. ESP failure in the Forties Delta well FD5-1 was found to be due to pack-off from a high proportion of fine shale/siltstone in addition to formation sand. Although simultaneous fracturing and gravel packing are commonly performed in other hydrocarbon producing regions none had been directed at controlling the mechanism of flowing shales and/or claystones.
The well intervention was designed to protect the ESP from shale or sand grain production and provide minimal impairment to well productivity. Both objectives were achieved by increasing the formation face area for inflow and in so doing physically support the formation face in the first such frac and pack treatment executed in the UK Sector of the North Sea. ESP protection was achieved and subsequent well productivity was show to be minimally affected by the presence of the gravel pack.
This case history describes the formation failure mechanism; the detailed corrective well intervention and the resulting well productivity in bring well FD5-1 successfully back into full production up-time.
The Influence of Viscoelasticity on Displacement Efficiency—From Micro- to Macroscale
Authors: Wang D. , Wang G. , Wu W. , Xia H. , Yin H. 
Published: December 2007

Abstract
The displacement efficiency (De) in porous media is usually analyzed by the ratio of the macro pressure gradient driving force and interfacial tension (IFT) between the driving fluid and residual oil. However, when the pressure gradient is constant, macro forces cannot explain the increase in De by driving fluids with elastic properties. Therefore, the change of micro forces acting on residual oil between driving fluids with and without elastic properties is analyzed.
This paper shows the influence of viscoelasticity on De; the difference in the stress of non elastic fluids and fluids with elastic properties when flowing is analyzed; the effect of this stress difference on the micro flow lines in pores is mathematically simulated; the affect of the changes in micro forces caused by the change in micro flow lines on residual oil is shown; this enhanced micro force (without changing the macro pressure gradient) mainly acts on the protruding portion of different types of residual oil in pore(s), causing the protruding portion to change shape and move (mobilize); results on visualization core models confirm the above calculation and analysis; the displacement results on cores by fluids with different elastic properties in the lab are shown; the results of considering the phenomena that elasticity increases the De in numerical simulation are shown and compared with field results; large scale field results on polymer flooding and pressure coring are also shown.
The above mathematical simulation, analysis, lab tests and field results all show that the micro forces acting on residual oil is different when the elastic properties of the displacing fluid varies, resulting in an increase in De for viscoelastic displacing fluids at constant pressure gradient conditions.
This method of micro flow line and force analysis and its conclusions should be useful to further understand the mechanism of De in porous media; should be useful in designing, screening and developing better chemical flooding products, methods and projects to further increase oil recovery; should be useful in the analysis of phenomena associated with injecting non Newtonian fluids and gels.
Artificial-Intelligence Technology Predicts Relative Permeability of Giant Carbonate Reservoirs
Authors: Al-Fattah Saud M. 
Published: December 2007

Abstract
Determination of relative permeability data is required for almost all calculations of fluid flow in petroleum reservoirs. Water-oil relative permeability data play important roles in characterizing the simultaneous two-phase flow in porous rocks and predicting the performance of immiscible displacement processes in oil reservoirs. They are used, among other applications, for determining fluid distributions and residual saturations, predicting future reservoir performance, and estimating ultimate recovery. Undoubtedly, these data are considered probably the most valuable information required in reservoir simulation studies. Estimates of relative permeability are generally obtained from laboratory experiments with reservoir core samples. Because the laboratory measurement of relative permeability is rather delicate, expensive and time consuming, empirical correlations are usually used to predict relative permeability data, or to estimate them in the absence of experimental data. However, developing empirical correlations for obtaining accurate estimates of relative permeability data showed limited success and proved difficult especially for carbonate reservoir rocks.
Artificial neural network (ANN) technology has proved successful and useful in solving complex structured and nonlinear problems. This paper presents a new modeling technology to predict accurately water-oil relative permeability using ANN. The ANN models of relative permeability were developed using experimental data from waterflood core tests samples collected from carbonate reservoirs of giant Saudi Arabian oil fields. Three groups of data sets were used for training, verification, and testing the ANN models. Analysis of results of the testing data set show excellent agreement with the experimental data of relative permeability. In addition, error analyses show that the ANN models developed in this study outperform all published correlations.
The benefits of this work include meeting the increased demand for conducting special core analysis, optimizing the number of laboratory measurements, integrating into reservoir simulation and reservoir management studies, and providing significant cost savings on extensive lab work and substantial required time.