bluuebunny/crossref_metadata_2025_split huggingface dataset:
Integrity of Bounding Seals for Geological Storage of Greenhouse Gases
Authors: Jimenez J. A. , Chalaturnyk R. J. 
Published: December 2007

Abstract
The injection of CO2 will give rise to a variety of coupled physical and chemical processes, which may affect the hydraulic integrity of caprocks. Likewise, when CO2 is stored as a component of EOR projects, the initial depletion of the reservoir, and all the influences associated with the EOR processes may affect the hydraulic integrity of caprocks. Therefore, it is necessary to understand how the hydraulic integrity evolves to make geological storage of greenhouse gases a feasible option. Such information must be imbedded in a performance assessment to determine the integrity of a reservoir and its caprock over an extended period of time. A preliminary methodology to evaluate the hydraulic integrity of the Weyburn project is presented.
Numerical Simulation of the Coupled Behavior of Faults During the Depletion of a High-Pressure/High-Temperature Reservoir
Authors: Charlier R. , Fourmaintraux D. , Samier P. , Radu J.-P. , Guiducci C. 
Published: December 2007

Abstract
This paper presents the study of the coupled hydro-mechanical behavior of a faulted HP-HT hydrocarbon reservoir during depletion. Because of the large expected depletion, a number of phenomena may be enhanced, all related to the changes during production, of the in-situ stresses, which control the mechanical response of the reservoir. This includes essentially two types of deformation, the first one being the reactivation of in the reservoir existing faults, while the second one is the reservoir compaction. The objective of this paper is principally to present the study of the first phenomenon, and more particularly their hydro-mechanical aspects. The study has been carried out with the help of numerical simulations of the fully coupled hydro-mechanical behavior of 2D reservoir models, using the finite element code LAGAMINE.
Optimization of Drilling Fluid Design for Managing Wellbore Instability in K-Shale in the Malay Basin of Peninsular Malaysia
Authors: Tan C. P. , Yaakub Mohd Azriyuddin , Chen X. , Willoughby D. R. , Hamid Pauziyah Abdul , Wu B. , Zamanuri Ibrahim , Zahari Ibrahim 
Published: December 2007

Abstract
Drilling experience in K-shale in the Malay Basin of Peninsular Malaysia highlighted the issue of wellbore stability in the formation. A wide range of drilling problems has been experienced, ranging from sloughing shale to tight hole and stuck pipe. Subsequently, a major collaborative project between CSIRO Petroleum and PETRONAS Research & Scientific Services Sdn Bhd was conducted to address the problems. The aim is to develop a technical framework of drilling fluid design and consolidate into a methodology for overcoming wellbore instability-related problems in the shale.
This paper describes the outline of the project and the approach adopted in the development of the methodology. The approach is based on drilling fluid-shale interaction and proven rock mechanics principles which include an extensive laboratory testing program on downhole core specifically cut for the study. Based on the gathered drilling experience and laboratory tests conducted on downhole core material, dominant time-dependent failure mechanisms of the shale were identified. Examples of critical mud weight contour plots and design charts of pressure change (due to drilling fluid-shale interaction mechanisms) which form part of the consolidated methodology for designing optimal drilling fluid are presented. Comparisons between predicted mud weights determined from the contour plots and mud weights used in one of the fields showed an overall good agreement between the mud weights, drilling experience and hole size. Counter to operational expectations, the results from the laboratory study showed that some water-based muds, through correct fluid design, are capable of preventing time-dependent instability in the shale.
The methodology provides a pragmatic approach for managing shale instability problems in drilling extended reach wells in the Malay Basin as well as other regions worldwide. The approach would result in an increase in drilling efficiency and a reduction in drilling cost.
Stability of a Multilateral Junction: Experimental Results and Numerical Modeling
Authors: Papanastasiou P. , Sibai M. , Heiland J. , Shao J-F. , Cook J. , Fourmaintraux D. , Onaisi A. , Jeffryes B. , Charlez P. 
Published: December 2007

Abstract
We studied the stability of multilateral junctions in a combined experimental and numerical modeling program. The experiments were carried out in a true triaxial machine on large size cubical blocks (40 cm) of weak triassic sandstone with two holes intersecting. Six tests have been performed with two different geometrical configurations and three different stress states. The experimental results are presented and compared with numerical modeling obtained with finite element software developed for assessing the integrity of rock surrounding a multilateral junction.
Sand Production Prediction of Gas Field - Methodology and Field Application
Authors: Wu B. , Tan C. P. 
Published: December 2007

AbstractA model has been developed for sand production prediction in gas wells. The model is based on linear poroelasticity and brittle plasticity with a critical equivalent plastic strain as sand production initiation condition. It included effect of residual strength in the plastic zone surrounding the cavity. The model has been applied to sand formations in a gas well in offshore North West Australia. The calculated drawdown pressure is higher than that based on linear poroelasticity but lower than the predictions based on the plasticity model without including the residual strength effect previously developed.
Assessment Of Several Sand Prediction Models With Particular Reference To HPHT Wells
Authors: Vaziri Hans , Xiao Yuing , Palmer Ian 
Published: December 2007

Abstract
HPHT wells represent one class of problems where the performance of current sand prediction models has not been properly evaluated. We applied three different sanding models to a cluster of six HPHT wells. In all these wells, no sanding was observed under considerable levels of drawdown, certainly far surpassing conditions required for sand failure. Moreover, under failed conditions, the wells were producing high rates of gas for very long periods.
The approaches used included popular analytical shear failure and tensile failure based models which showed an unusually high level of conservatism in their prediction of sanding in high pressure wells. We provide a plausible explanation for this behavior which is attributed to the underlying proposition that sand production occurs when sand fails. While this supposition is used in all applications of such models, in deep, high stress and pressure systems, the problem is magnified due to the fact that failure occurs relatively early in the operating life of the reservoir. We propose an alternate approach where sand production criterion is extended to include not only sand failure but also adequate seepage forces to liquefy the sand and hence mobilize it. This approach is shown to better capture the observed response in the field. As an added bonus, the proposed approach quantifies the volume of sand rather than simply give indications of the onset of sand production. This information is helpful in developing the optimal production strategy throughout the life of field.
In this paper, we discuss the pros and cons of the commonly used models for sand prediction and provide examples to validate the newly proposed concepts for quantifying sand production.
Geomechanical and Thermal Reservoir Simulation Demonstrates SAGD Enhancement Due to Shear Dilation
Authors: Collins P. M. , Carlson M. R. , Walters D. A. , Settari A. 
Published: December 2007

Abstract
A novel numerical analysis is described, in which the steam-assisted gravity drainage (SAGD) recovery process in bituminous oil sand is studied. A geomechanical/reservoir simulator was modified to incorporate the absolute permeability increases resulting from the progressive shear dilation of oil sands. The objective was to obtain a realistic prediction of shear dilation, as the oil sands approached failure and beyond, and the concomitant increases in permeability. Changes in the in situ stresses that caused this dilation were due to the combined effects of reduced effective stress with high-pressure steam injection, and increased deviatoric stress with thermal expansion under lateral confinement. The resultant volumetric strains were used to modify the absolute permeability characteristics of the oil sands as the SAGD process progressed. The spatial and temporal growth of enhanced permeability zones resulted in an accelerated steam chamber growth.
The relationship between volumetric strains and absolute permeability changes was obtained from existing laboratory data on quality specimens of non-bituminous Athabasca oil sands. The source sample was obtained from an outcropping of the McMurray Formation, thus avoiding most of the sample disturbance associated with unconsolidated core obtained conventionally. Under triaxial loading, the resultant volumetric strains increased absolute permeabilities by a factor of 4 to 6.
The analysis is innovative in that the model used an effective stress approach, and used the volumetric strains to modify absolute permeabilities. Thus, the encroaching SAGD steam chamber was found to modify the stress regime, which in turn modified the permeabilities within the reservoir. Geomechanical enhancement of the SAGD process was found to be a significant beneficial effect, and would be increased by operating the SAGD process at higher injection pressures.
Extrapolation of Rock Mechanical Properties From a Cored Well to an Uncored Well Through the Use of Electrofacies
Authors: Miskimins Jennifer , Graves Ramona , Hurley Neil , Barree Robert 
Published: December 2007

Abstract
A technique for extrapolating core-measured rock mechanical properties from a cored well to an uncored well is presented. The process uses electrofacies and square wave techniques to develop rock mechanical property logs for the uncored wells.
Data from the North LaBarge Shallow Unit (NLBSU) is used to develop the process. The NLBSU wells require hydraulic fracturing to generate economic production rates. The NLBSU produces from Cretaceous-age Mesaverde sandstone that is composed of thinly bedded sand and shale layers. The reservoir heterogeneity caused by these layers complicates hydraulic fracture growth characteristics. Improvements in hydraulic fracture simulation are needed to accurately predict these growth characteristics. This includes improvements in input data, such as rock mechanical properties, for the simulations.
The described methodology uses electrofacies developed from core and FMI in one well and extrapolates the electrofacies to other wells via an AO10 induction log curve (depth of investigation 10 in (25 cm)). Induction logs are run in almost every well in the field and provide a universal extrapolation medium without incurring additional costs. The process uses acoustic velocity measurements for rock mechanical values, but any accepted measurement technique can be used. Only two major facies are present in the NLBSU and the presented technique only addresses the two facies. However, the methodology can be expanded to include more facies if cutoff values can be established.
The process described in this paper is being used to improve hydraulic fracture modeling in the NLBSU. It can be used in other fields which need improved modeling also. Additionally, it can be used for any computer simulation program that requires rock mechanical property input including reservoir simulation and wellbore stability programs.
Dynamic Optimization of Water Flooding with Smart Wells Using Optimal Control Theory
Authors: Brouwer D. R. , Jansen J. D. 
Published: December 2007

Abstract
We used optimal control theory to develop optimization algorithms for the valve settings in smart wells. We focussed on their use in injectors and producers for waterflooding of heterogeneous reservoirs. As a follow-up to an earlier, intuitive, optimization approach, we developed systematic algorithms and investigated the effect of well constraints on the scope for optimization. The objective was to maximize recovery or net present value over a given time period. We concluded that: 1) For wells operating on bottom hole pressure constraints the benefit of using smart wells is mainly reduced water production rather than increased oil production. 2) For wells operating on rate constraints, there is a very large scope for accellerating production and increasing recovery, in combination with a drastic reduction in water production.
Modeling and Flow Simulations of a North Sea Turbidite Reservoir: Sensitivities and Upscaling
Authors: Stephen K. D. , Clark J. D. , Pickup G. E. 
Published: December 2007

Abstract
We have created a variety of detailed geological models, in order to carry out a sensitivity study in a turbidite oil reservoir. The base case stochastic model was generated using well-log data, seismic attribute data and information from outcrop analogues. In addition, some small-scale models were created to capture the effects of fine sedimentary structure (mudstone intra-clasts, and interbedded sandstone and mudstone layers).
The main focus of this paper is on the flow simulation, upscaling and sensitivity analysis, rather than on the geological modelling. We carried out a range of sensitivity studies on two-phase flow parameters, gridding effects and upscaling. Our results show that the large-scale geological structure is potentially dominant. Integration of seismic information and the definition of zone transitions is crucial if an adequate history match is to be obtained. Redistributing the facies by successive realisations also impacted strongly on the productivity. The dominant two-phase flow property was wettability, particularly the shape of the capillary pressure curve, which could lead to a large capillary transition zone.
In this particular field, the fine-scale structure, as modelled for two genetic units, did not have a large impact on the results, because these units occurred in isolated regions and were largely by-passed. Small scale heterogeneity in the main Channel Sandstone genetic unit did impact on flow, however.
The Use of a Virtual Chemistry Laboratory for the Design of Matrix Stimulation Treatments in the Heidrun Field
Authors: Ziauddin M. , Kotlar H. K. , Vikane O. , Frenier W. , Poitrenaud H. 
Published: December 2007

Abstract
In this study, a new technique for designing matrix stimulation treatments is examined. The technique uses a geochemical simulator in combination with simple experiments with batch reactors and short reservoir cores. The new technique is compared with alternative design techniques, such as those using long core flow tests and laboratory radial flow setups. The strengths and weaknesses of the design techniques are presented.
The effectiveness of the treatment design with the new technique is evaluated with a case study on a well in the Heidrun field. It was found that compared to alternative approaches, the new technique provides a simpler, faster, and cost-effective method for treatment design. Furthermore, the new technique also provides a more accurate scaleup to reservoir flow conditions than other design alternatives. The improved accuracy results from more precise accounting for reservoir and damage mineralogy and radial flow. Heidrun is a heterogeneous reservoir with high clay content. We found that these effects were more practical to examine with a validated simulator than with specially designed laboratory experiments.
Treatment design in the case study was difficult because the target well was the first to be acidized in the formation. As no prior stimulation experience existed, a reliable means of treatment design was required. We show how the new technique can be used to develop such a design. Post-treatment data from the well showed a successful matrix treatment design. The productivity index for the well increased from a pre-treatment value of 20 to a post-treatment value of 55 m3/day/bar at standard conditions.
Improved Rt And Sw Definition From The Integration Of Wireline And LWD Resistivities, To Reduce Uncertainty, Increase Pay And Aid Reservoir Navigation
Authors: Page G. , Benefield M. 
Published: December 2007

Abstract
The measurement of true formation resistivity (Rt) in order to determine fluid saturations, has resulted in the development of a wide variety of wireline and logging while drilling (LWD) measurement systems. These devices are generally treated as independent systems when determining Rt and fluid volumetrics. However, the sensor technologies are complementary, and all available data can be used together to effectively reduce uncertainties inherent in the single data sets. This results in more accurate water saturation (Sw) calculations, and reduced reservoir uncertainties. Techniques, which will be discussed, are not limited to mathematical models and inversion, but include methodologies for identifying the best acquisition strategy in order to acquire the required data, correct preparation for geosteering and reservoir navigation.
The development of wireline tensor resistivity devices that are capable of measuring transverse electrical anisotropy has significantly improved the quantification of fluid saturations in thin bedded formations, and even thicker formation units drilled through at high apparent dip. Additional low contrast pay zones have also been identified which were missed by traditional techniques. In certain circumstances LWD measurements can be used to provide an initial qualitative assessment of electrical anisotropy, and determine if these specialised wireline measurements would be beneficial in order to quantify fluid saturations. The identification of these zones will be discussed with the benefits and limitations involved.
Where tensor resistivity data is available it can significantly improve the geological models used for geosteering. Incorporation of this data can predict anomalies not seen on simple models, which may be interpreted incorrectly resulting in unnecessary wellbore deviations, and loss of reservoir penetration. Examples of these effects, and their magnitude, will be used to demonstrate the importance of incorporating electrical anisotropy in the models.
10 Years of WAG Injection in Lower Brent at the Gullfaks Field
Authors: Instefjord Rune , Todnem Annick Chazy 
Published: December 2007

Abstract
The Gullfaks field is a large oil field in the Norwegian sector of the North Sea. Production started in 1986 with water flooding as the primary recovery method. A WAG injection pilot in lower Brent well A-11 was initiated in March 1991. The well is located south in the GFA-area.
A simulation model was built and history-matched until January 1993 for the whole pilot area, including upper Brent. Predictions to the end of year 2005 indicated an increased oil recovery of 0.3 mill. Sm3 in addition to some accelerated production. Most of the predicted increased oil recovery was however reached during 1993.
The WAG injection has continued in A-11 but with fewer gas periods the last years. The updated estimate of increased oil recovery from WAG injection in A-11 up to year 2001 is 2 mill. Sm3.
The paper will also give a short evaluation of WAG injection in two other lower Brent injectors at Gullfaks with a joint estimated increased oil recovery of 0.7 mill Sm3.
Optimisation of an Aggressive Drilling Programme at the Statfjord Field - Maximising Production in a Mature Field
Authors: Hansen Anne-Grethe , Brendsdal Atle , Arnesen Dag Schistad , Morris Marian 
Published: December 2007

Abstract
The giant Statoil-operated North Sea oil field Statfjord is currently far down its production decline curve. During 23 years of production more than 60% of the STOOIP has been recovered, and the remaining reserves are characterized by complex distributions of oil, water and gas.
In order to obtain a cost-effective production of the remaining oil, an aggressive drilling and intervention programme is necessary. The main challenge that the geoscientists and reservoir engineers face in this scenario is to identify remaining oil in targets becoming increasingly smaller, more complex and more uncertain, and to drain these in the most profitable manner. This paper reviews the working method that has been used at the Statfjord Field when defining a drilling schedule. It shows how the different work processes are linked, starting with the identification of possible new well locations, continuing with the estimation of reserves and risk evaluation and ending up with final drilling projects.
Minimizing Energy Cost by Maintaining High Volumetric Pump Efficiency
Authors: McCoy J. N. , Becker D. J. , Rowlan O. L. , Podio A. L. 
Published: December 2007

Abstract
Many wells operate in the United States with beam pump artificial lift equipment. Most of these wells have a pump capacity that exceeds the production rate of the well. These wells would operate more efficiently and at a lower cost if they operate with a full pump. This requires the elimination of gas interference in the pump, insuring that the pump has no mechanical problems and then optimizing the run time so that the well operates periodically, yet removes all the available liquid from the wellbore.
Optimization of the pumping system requires an integrated analysis1 of the prime mover, surface equipment, wellbore equipment, downhole pump, downhole gas separator and the reservoir. Analysis is based on information obtained from liquid level instruments, dynamometers and motor power probes.
This paper reviews the analysis of the pumping system and then discusses the various methods of controlling the operating time with devices such as timers and pump off controllers. Using the integrated analysis method presented in this paper, the operator can monitor pump fillage and set run time on these devices, thereby efficiently producing his well.