bluuebunny/crossref_metadata_2025_split huggingface dataset:
Resolution of a Multi-Set, Strike-Slip Dominated Fault System, Identified from 3D Seismic, in Early Cretaceous Carbonate Reservoir Sequences of a Giant Offshore Field in Abu Dhabi
Authors: Edwards E. , Al-Rougha H. B. , Sit H. , Sultan A. , Khouri N. 
Published: December 2007

Abstract
Recent mapping of fault patterns from picked surface attribute analysis (‘difference’ maps, spectral decomposition, isochron maps) and time slices over a giant offshore field in Abu Dhabi has recognized a complex multi-set pattern of faults at reservoir level. As well as providing additional seismic scale faults, linear features (proposed subseismic faults and fracture systems) have been identified. These patterns are best described in terms of strike-slip geometries; however, many display components of both dip-slip and strike-slip over their movement history. In different parts of the field dominant fault directions displaying dextral transtension, dextral transpression, trapdoor hinge faulting and oblique-slip keystone graben generation are observed. Fault throw statistics and segment growth history in the most important mapped zones typify components of strike-slip along with local shear and segment termination at cross-fault zones. The prevalent fault trends are roughly orthogonal NE-SW and NW-SE systems that dissect the field. Superimposed on this geometry is an array of distinctly en-echelon WNW-ESE and WSW-ENE structures that link to steep zones at deeper levels. Within sub-regions of the field other trends are also present, including NNE-NNW to N-S, NNW-SSE and E-W. These sets do not form a radial pattern; they are distributed spatially within field domains and involve complex systems and layer-related rheologically controlled deformation.
Comparison of the mapped lineament pattern with core-derived fracture orientation data shows that all sets identified in the field from seismic are present within the overall fracture strike system within the wells. Field-wide, domains where transtension and transpression dominate, as well as more dip-slip dominated areas can be mapped out. Core scale fractures tend to display a component of strike-slip within the bulk strain field-wide, as evidenced by steep or sub-vertical fracture intersections. Newly identified lineament zones allow better understanding of high intensity fractured wells previously mapped distal to known faults
Origin and Potential of Unconventional Jurassic oil reservoirs on the northern Arabian Plate
Authors: Goff Jeremy 
Published: December 2007

Abstract
Unconventional oil reservoirs exist in deep, overpressured, fractured carbonate source rocks, and in adjacent dolomitised carbonate platforms, in the Jurassic Gotnia Basin on the northern Arabian Plate. These reservoirs are an important potential future resource for the region once the low risk prospect inventory in conventional plays is drilled out, and production from their reservoirs inevitably reaches a plateau. An estimated 5 – 10 trillion barrels of oil have been generated in the Jurassic source kitchen; recovery of just 0.5% of this volume would yield substantial oil reserves. A high proportion of the generated oil has probably been retained in secondary porosity within the Jurassic Petroleum System, beneath an evaporite caprock. Pore pressure gradients approaching 1 psi/ft during oil generation (at pore pressures of 10,000 – 20,000 psi), and localized folding in Late Jurassic, Turonian and Late Tertiary time, have created a complex fractured reservoir system within the Jurassic source rocks and interbedded carbonates. Sustained production from the source rock reservoirs may only be possible in areas where oil filled microfractures are able to recharge large connected permeable tectonic fractures during pressure drawdown. Dolomitising fluids and oil have migrated into carbonate platforms underlying, and flanking, the source kitchen. Fluid inclusion studies indicate that dolomitisation occurred at temperatures of 80 – 140 deg C from pore waters with salinities of 100,000 – 250,000 ppm, locally creating world class oil reservoirs (sealed by tight limestones) seen at outcrop in the Zagros Mountains on the deformed eastern margin of the basin. Successful exploration and development of the Jurassic reservoirs will be challenging - requiring pre drill seismic imaging of fracture systems and of laterally discontinuous porous dolomite units, application of unconventional wells in challenging drilling environments, and careful reservoir management during production to achieve commercial recovery factors.
Enhancing Marginal Field Development Economics by Leasing Operated Production Facilities
Authors: Maclean A. 
Published: December 2007

Abstract
Innovative technical advances are now enabling operators to consider development of fields previously identified as uneconomic or marginal. However such projects can still fail to progress since development using a traditional engineering, procurement and construct (EPC) approach does not always meet the required targets for economics, risk and timescale necessary for approval to proceed.
In this paper the author will detail how the use of fit-for-purpose production facilities mobilised on a leased, operated and maintained basis now offers an alternative approach to the provision of a field production solution. This approach enables operators to limit their initial set-up and infrastructure costs at the front end of a project, to gather additional information on the performance and productivity of their wells and to make a more informed decision on the future of the field. As a result, operators can keep both their project and capital risk exposure to a minimum.
By achieving this production on a fast-track basis, revenue from the sale of produced well fluids is generated early. Combined with the low initial cost and lower capital risk of this approach, the economic viability of progressing an asset to full scale production is further enhanced. Based on this sequential investment model, a real option analysis of the overall field development plan can therefore make a project viable, even if the overall project net present value (NPV) appears marginal using more traditional methods.
In conclusion the paper will present technical solutions for the various field evaluation and production stages of a full field development utilising the leased facility approach, associated commercial models and case studies for recently completed projects.
Structured Uncertainty Assessment for a Mature Field through the Application of Experimental Design and Response Surface Methods
Authors: Salhi M. A. , Van Rijen M. , Wei L. , Dijk H. , Alias Z. , Upadhyaya A. , Lee H. 
Published: December 2007

Abstract
This study covers one of the largest and oldest oil fields in Oman. Despite over 35 years of production through various drive mechanisms, there remains an opportunity to realize additional value in the field.The scale and complexity of the uncertainties associated with such opportunity necessitates the use of experimental design and response surface methods to provide a framework for evaluating sensitivities and estimating impact of uncertainties on field performance.
Since data sometimes are incomplete or inconsistent and measurements are ambiguous or inconclusive, the representation of reservoir and geological parameters are often sub optimal. This is especially true for heterogeneous fractured reservoir, such as this field, where the number and range of uncertainties is large.This paper presents the application of experimental design and response surface methods to the field development study of this field.
The methodology uses an integrated approach, where cross discipline data is evaluated early in the study to identify and quantify uncertainties with the highest impact. After static and dynamic data are reviewed and quality checked, an initial ranking of uncertainties takes place. A selection of 3D simulation models, as defined by the experimental design approach, are run to construct response surface models, which are then used to assess the impact of these uncertainties on field behavior. The historical performance of the field is critical data used to constrain the range of some uncertainties. The results of this study are used to guide future development of the field.The methodology described in this paper highlights the value of a structured multiple realization approach, using experimental design and response surface modeling, for uncertainty estimation and management.
First Deep Horizontal Multi-Lateral Gas Well: Objectives, What We Got, Lessons Learned and Next Steps
Authors: Ginest N. H. , Asiri K. S. , Al-Gouhi W. A. , Haas M. D. , Hembling D. E. , Duncan M. W. 
Published: December 2007

Abstract
Saudi Aramco's first deep Level 3 Plus multi-lateral (ML) gas wells were drilled in the ‘Unayzah sandstone gas reservoirs in the remote Delta (D) Field. This paper describes the processes that were conducted during the initial planning stages by the multidisciplinary development team, the well construction and completion operations, and the post well construction reviews that were conducted to document lessons learned and to make recommendations for process improvements. Extensive detailed planning, a multidisciplinary team approach and solid operations planning and performance led to overall success and paved the way for continued field development with maximum reservoir contact (MRC) well completions.
This paper discusses the development of the reservoir exploitation strategy, the well construction and completion operations, and future well servicing options. The overall strategies included maximizing well deliverability with minimum drawdown, focusing on initial well completion efficiency to minimize formation damage and well intervention requirements, and providing a rigless means to isolate water production from the lower lateral in the future.
Permanent Downhole Pressure Gauges Help Underpin Feasibility of Miscible Gas Flood
Authors: Laws M. S. , Matsuura T. , Soek H. F. , O'Dell P. M. , Kinsella T. J. F. 
Published: December 2007

Abstract
This paper describes a part of the strategy that was developed to demonstrate that a gas flood will be feasible in the Harweel Cluster in Southern Oman.In order to prove this, eight producers and six observation wells were predrilled in four of the reservoirs within the Cluster. During primary production, it was essential to measure downhole pressure data in the observers for a period of up to 2 years.The magnitude and timing of the pressure response at the neighbouring observation wells are indications of the amount of storage (porosity) and the degree of connectivity (permeability) and are therefore key subsurface characteristics.Consequently, permanent downhole pressure gauges were fitted in 11 out of the initial 14 wells (i.e. gauges were also fitted in selected producers as a back up, demonstrating the importance of this information in underpinning the final investment decision to proceed with a gas injection project).The gauges were installed as close to the reservoir as possible to minimise thermal excursion on shut down and start up.A comprehensive analysis of industry wide data was undertaken to determine those vendors capable of providing gauge systems of the required precision and reliability.
In the first field to be evaluated, one of the wells was produced initially while the other three in the field were set up for observation.Pressure drops were observed on all neighbouring wells indicating they were in communication.This data removed one of the major uncertainties impacting gas flood feasibility as it shows that there is no significant degree of reservoir compartmentalisation.Further reservoir characterisation information has been obtained from the magnitude of the pressure response (100-1000 kPa depending on the distance from the producer) and timing (initial response within 1 month).The data from these gauges has clearly helped to underpin the feasibility of a miscible gas flood in this field.
The Fracture Characterization and Fracture Modeling of a Tight Carbonate Reservoir: The Najmah Sargelu of West Kuwait
Authors: Fonta O. , Al-Ajmi H. , Verma N. K. , Matar S. , Divry V. , Al-Qallaf H. 
Published: December 2007

Abstract
This paper presents an innovative and promising, multi-discipline integrated approach that includes geology (BHI, cores, wireline logs), geophysics (seismic facies analysis), and reservoir engineering data (production data, PLT, welltest) that were combined to identify the main types of fractures, to predict their occurrence in the reservoir and to determine the hydraulic properties of the different fractures sets
The Najmah – Sargelu of West Kuwait is an oil bearing reservoir made of tight carbonates where porosity and permeability is mainly provided by the fracture network. In this paper, we will first introduce the method used to identify and predict the two main scales of fractures: joints and large-scale fractures (faults and fracture swarms). The shale content (Vshale) and mechanical beds thickness were found to be the two main geological drivers on joints occurrence. Thickness of individual beds were recorded from BHI acoustic images which enabled to measure an S/T ratio (fracture spacing to bed thickness) for each fracture set and for different shalyness. Secondly, we used an innovative solution to deliver an accurate map of large-scale fractures location. This approach uses concurrently a set of selected fracture relevant attributes in a multi-variable statistical process called Seismic Facies Analysis (SFA).
A 3D stochastic fracture model was then generated incorporating the two scales of fractures and constrained by the reservoir shalyness, the S/T ratio and the seismic facies map. The calibration of the hydraulic properties of the fractures was achieved through the second innovation presented in this paper: the simulation of a synthetic well test using the 3D fracture model and matched with the real data. This resulted in the calibration of the hydraulic fractures conductivity for each fracture type. These values were combined with the 3D stochastic fracture model to produce 3D fracture properties models (porosity, permeabilities and block size) for the Najmah – Sargelu of West Kuwait.
Modeling and Designing Improved Oil Recovery by Steam Injection in Naturally Fractured Reservoirs
Authors: Cicek O. 
Published: December 2007

Abstract
Steam injection in naturally fractured reservoirs provides an extremely challenging problem as well as a potentially effective and efficient improved oil recovery method. Coupling of the two distinct and contrasting matrix and fracture systems results in a highly non-linear problem, and it gets even more complicated as a result of steep changes in fluid properties due to the thermal effects of steam injection. Modeling and designing an optimum steam injection operation in such systems requires an accurate characterization and representation of a naturally fractured reservoir and steam injection operation parameters and dynamics.
In this research effort, a thermal dual-permeability/dual-porosity numerical model is developed for the problem. The multi-phase fully implicit model is three dimensional and compositional, accounting for viscous, capillary and gravitational forces. The model incorporates detailed anisotropic and heterogeneous reservoir property description, and formulates all reservoir and operational parameters as functions of all the primary variables, (2nHC+10), where nHC is the number of hydrocarbon components. The multi-layer production and injection wells are coupled to the reservoir fully implicitly. Both an iterative and a direct solver are employed in the solution of the resulting system of linear equations. The present model is verified and benchmarked against two SPE Projects.
A comprehensive and comparative study is conducted in order to understand the relative effects of naturally fractured system and injection operation properties on the oil recovery performance. This comparative sensitivity analysis is performed using the dual-permeability, the dual-porosity and the approximate conventional single-porosity model.
In search of some practical guidelines, each reservoir system and operational property is studied in a range of naturally fractured reservoirs such as with different matrix block sizes, fracture/matrix permeability ratios and capillary pressures. The present study should help us better understand fluid flow dynamics, design optimum recovery operations and determine range of confidence for an oil recovery operation in naturally fractured reservoirs undergoing steam injection.
Downscaling Geomechanics Data for Thin Beds Using Petrophysical Techniques
Authors: Qiu K. , Marsden J. R. , Solovyov Y. , Safdar M. , Chardac O. , Shatwan M. 
Published: December 2007

Abstract
Thin-bed sequences, especially those made up of alternating weak and strong sand layers with thickness of less than 1-ft, present a particular challenge in the generation of mechanical earth models (MEMs) for geomechanics design and analyses. Because these beds are thinner than the tool resolution, their heterogeneity and the variations between adjacent layers are often undetected by logging tools normally used to acquire geomechanics data. In other words, these tools cannot resolve the existence of alternating strong and weak sequences; they provide only averaged mechanical properties across these sequences.
In one such case, an MEM and sanding study based on wireline sonic data indicated no tendency for sanding across a thick reservoir interval at the drawdowns required for economic oil production. The somewhat flat, log-derived curve of unconfined compressive strength (UCS) indicated that the entire reservoir was above the critical sand-free UCS state; however, laboratory data had revealed a large spread in UCS values, including rock strength values that are indicative of a significant sanding risk. In fact, the field had a history of solids production with depletion.
Using the high-resolution images (with vertical resolution of 0.2 in.) provided by a microresistivity imaging tool across the same thin-bed intervals, and using alpha processing and other petrophysical log enhancement to further improve data interpretation, it was possible to generate a high-resolution (around 0.2 in.) porosity log. These downscaling techniques were combined with an empirical UCS-porosity relationship obtained from the available laboratory data. The resulting downscaled UCS log exhibited the wide range of strength values that were known to exist across the thin-bed sequence and were consistent with the history of sand production in the field.
The remaining sanding evaluation for the well was completed using this integrated petrophysics and geomechanics approach. When the MEM and sanding analyses were extended to other wells in this field, the results matched well with the actual depletion curves and sanding history data.
A Miscible WAG Project Using Horizontal Wells in a Mature, Offshore, Carbonate Middle East Reservoir
Authors: Schneider C. , Shi W. 
Published: December 2007

Abstract
This paper summarizes the design, operation, results, and reservoir modeling of a miscible hydrocarbon gas injection pilot using horizontal wells in the Fateh Mishrif, a large carbonate reservoir in an offshore operating environment.The pilot included a single horizontal water-alternating-gas (WAG) injector flanked by two horizontal producers drilled near the base of the reservoir.The three-well pattern was surrounded by four water injectors which provided confinement and pressure control.Produced gas from the field was used for injection without supplemental enrichment.
The pilot began operations in 1997. Commencing in 1999, gas was injected in three cycles over a period of four years. A clear incremental oil rate response to the gas injection was first observed in early 2003, peaking with a 400% incremental oil rate increase from the two producers.
Pilot results have been history matched with a compositional reservoir model to reconcile reservoir characterization interpretations and to provide prediction of ultimate recovery. Incremental recovery over waterflood operations is predicted to be 6% of original oil-in-place for 0.15 hydrocarbon pore volumes of gas injection.
Production Optimization in ESP Completions with Intelligent Well Technology by Using Downhole Chokes to Optimize ESP Performance
Authors: Vachon G. , Furui K. 
Published: December 2007

Abstract
Accelerated production, increased ultimate recovery, and reduced interventions are goals of any operating company. It is now possible to attain all of these goals simultaneously by retrofitting intelligent well technology to an existing, conventional completion. This task is much more complex when the new technology must be installed in conjunction with artificial lift, such as an electric submersible pump (ESP). However, new technology and procedures have overcome this complexity and offer a viable option for optimizing production in existing completions that use artificial lift.
Commingled or selective production from two or more zones is an ideal method of accelerating production from a single well. Traditional designs require interventions into the well to select the intervals to be produced. In most ESP wells, commingling is achieved by using "Y" blocks which allow production tubing to be run from the tubing hanger to the zones of interest. The ESP must then be downsized to accommodate this side-string, which significantly reduces available pump horsepower. This paper focuses on single-ESP wells producing from multiple pay zones. Various application patterns for use of intelligent well technology beneath ESPs are presented, especially focusing on immediate and future benefits. Theoretical examples are presented to illustrate how intelligent completions can enhance the ESP performance, add flexibility, and extend the range of application for a given pump.
JD as a Performance Indicator for Hydraulically Fractured Wells
Authors: Dietrich J. K. 
Published: December 2007

Abstract
Hydraulic fracture treatments are designed with a goal of maximizing the dimensionless productivity index (JD). Single-well, pseudo steady-state models are commonly used in the treatment design process, notwithstanding the fact that the stimulated well is often in a pattern water flood, and therefore, more nearly in a steady-state flow regime. Using a combination of analytical and numerical methods, it is shown that application of the pseudo steady-state solution to a steady-state problem invariably leads to over-prediction of JD and the benefits of hydraulic fracturing. As a solution to this exaggeration, there is a need to consistently apply the model having boundary conditions most like those of the field. The first step is to understand the differences and formally distinguish between the pseudo steady-state and steady-state dimensionless productivity indices; thus two purportedly new terms are introduced for this purpose: JDpss and JDss. Results demonstrate that JDss &lt;&lt; JDpss over the full range of fracture penetrations, the difference becoming greater with increasing fracture conductivity and penetration, reaching 50% at the theoretical limits and 30%, or more, at practical fracture conditions.
While multiple well interference effects are shown to be capable of limiting the achievable level of JD, there are actions that can be taken to greatly increase it: optimizing flood pattern shape and aligning patterns parallel to the hydraulic fracture azimuth are two measures that are each shown to be capable of increasing JD by 50%, or more.