bluuebunny/crossref_metadata_2025_split huggingface dataset:
Coupled Geomechanics-Fluid Flow Modeling: Effects of Plasticity and Permeability Alteration
Authors: Yale D. P. 
Published: December 2007

Abstract
Yale et. al.1 showed significant differences between "uncoupled" reservoir simulations of a highly compressible (but elastic) reservoir and the same model run with deformation and fluid flow "coupled" together. This paper utilizes a similar model but investigates the effect of plasticity of the reservoir rock and alteration of permeability with deformation on these coupled simulations.
The coupled simulations show that plasticity significantly increases the compressibility of the rocks and the compaction drive energy of the reservoir. The initial stress state of the reservoir is shown to have a large effect on the degree of plasticity and the degree of depletion for the same amount of fluid withdrawal and the same rock properties.
Modeling the change in permeability with deformation of plastic sands shows an extremely large effect on near wellbore pressure drawdown and deformation over normal reservoir simulations. The coupld geomechanis-fluid flow simulations show very strong interaction between pressure drawdown, plastic strain, and permeability.
Analysis of Horizontal Casing Integrity in the Valhall Field
Authors: Pattillo P. D. , Kristiansen T. G. 
Published: December 2007

Abstract
The Valhall field, located in the Norwegian Sector of the North Sea, is a high porosity chalk field characterized by its weak reservoir rock. Global field behavior during depletion includes extensive compaction and associated subsidence.
One highly successful completion alternative, horizontal wells, was, in its early application to Valhall, plagued by the premature failure of the production tubulars associated with reservoir draw down/compaction. Numerical modeling, with subsequent field implementation, has shown, however, that casing with sufficiently low diameter:thicknesses can withstand the rigors of draw down and associated formation loads. Unfortunately, the use of thick-walled casing presents its own difficulties in terms of installing the string (torque/drag) and the subsequent limitations on tool diameter (smart well completions, for example) associated with the stout cross section. Further, a one-size-fits-all doctrine is not optimal, in that the porosity, and therefore strength, of the reservoir rock varies laterally, thus penalizing well designs on the flanks of the reservoir where the chalk porosity is lower and chalk strength is, therefore, higher.
The current paper addresses the above issues by modeling the behavior of the wellbore and surrounding region. Starting with the virgin reservoir, the model considers (sometimes extensive) pre-wellbore depletion, drilling the wellbore, installation of casing and cement, and subsequent draw down. Significant variations to the model include the cross section of the production casing, the quality and quantity of the cement sheath and the perforation pattern. Behavior of these various configurations during subsequent draw down permits them to be ranked according to the life expectancy of the resulting completion. The discussion is enhanced by field results, as several of the completion alternatives have been installed in Valhall wellbores.
Rock Mechanics and Wellbore Stability Analysis While Drilling using LWD Sonic, Density and Caliper Measurements
Authors: Boonen Paul , McElhinney Graham 
Published: December 2007

Abstract
The art of rock mechanical and well bore stability analysis has moved to the real-time domain with the use of Logging-While-Drilling tools. Rock mechanical analysis based primarily on sonic logs (compressional and shear slowness) is a well established technique to identify wellbore stability issues. Logging-While-Drilling logs are slowly replacing wireline logs in large numbers of wells. Not only has the LWD data quality equalled wireline data quality, these data are now available in real-time while drilling. The rock mechanical analysis previously restricted to post drilling analysis, can now be done while drilling. The typically required sonic data (DTP and DTS), the bulk density and a shale indicator are sent to surface in reasonable time increments and the rock mechanical evaluation programs are installed on the rig site LWD systems. Alternatively, the data can be sent to service company or oil company's offices and analysis performed there.
In addition to traditional rock mechanical computations, a new technique is introduced to evaluate borehole break-out and its orientation while drilling using an LWD caliper measurement. The LWD caliper tool used in the North Sea examples employs three ultrasonic transducers to measure the stand-off between the logging tool and the borehole wall. The caliper is computed from these three measurements. In the new method we fit an ellipse through the three measurements and compute the minimum and maximum axes of this ellipse. With the tool face information provided by the LWD survey tool, we can compute the orientation of these axes. Where borehole breakout is resulting from stress relieve at the borehole wall, the direction of the long axis coincides with the direction of the minimum horizontal stress in the formation. Three dimensional borehole caliper images can be created after logging.
Geomechanical Fault Characterization: Impact on Quantitative Fault Seal Risking
Authors: Jones Richard M. , Dewhurst David N. , Hillis Richard R. , Mildren S. D. 
Published: December 2007

Abstract
Fault sealing is one of the key factors controlling hydrocarbon accumulations and can be a significant influence on reservoir behavior during production. Fault seal is, therefore, a major exploration and production uncertainty that requires a rigid, systematic framework within which to quantify the geological risk of trapping hydrocarbons. One of the key uncertainties in this risking procedure is the breaching of structurally bound traps due to the formation of structural permeability networks. Considering a population of faults and fractures, those that are critically stressed are more prone to act as conduits for fluid transmission. Evaluation and mapping of fault seal breach through such networks involves integration of in-situ stress conditions, pore pressure, fault architecture and fault geomechanics.
Geomechanical characterization of well-lithified fault rocks from the Otway Basin and the Northwest Shelf demonstrates that faults can exhibit significant cohesive strength and that fault reactivation and trap breach is influenced by the development of shear, tensile and mixed-mode fractures. The mechanics of the reactivation process are influenced by grain strength and fault morphology. Mercury injection capillary pressures of cataclastic faults indicate a seal capacity of 2400 psi. Following reactivation, seal capacity is reduced ∼95% due to the development of a highly connected fracture network. The tensile strength of such healed faults allows failure to occur by shear, tensile and mixed mode fracturing. These data suggest simple application of Byerlee's Law may not always be applicable when predicting reactivation induced fault seal failure. Consequently, geomechanical tools used to predict trap breach via reactivation that assume cohesionless frictional failure are likely to significantly underestimate seal reactivation risk.
The impact of structurally risking traps using Byerlee and laboratory-derived fault data is demonstrated using the Fault Seal Risk Web approach. Application of geomechanical fault data results in a significant reappraisal of prospect structural risk due to consideration of fault healing.
Analyses of Sonic Data in an Indonesian Well for Formation Damage, Stresses, and Bedding
Authors: Sinha Bikash K. , Kane Michael R. , Borland William H. 
Published: December 2007

Abstract
To help design the completion of an Indonesian development well, we have carried out cross-dipole dispersion analyses over a depth interval of approximately 500 ft. Dispersion analyses provide estimates of radial extent of formation damage and indicators of stress- and bedding-induced anisotropies. Most of these sections of this vertical well exhibit sand and shale lithology with shear slowness anisotropy ranging from 5 to 10%. Above the angular unconformity in the deeper section of the well, a clean sand interval (Sand A) shows evidence of cross-dipole dispersion crossovers. Crossing dipole dispersions are indicators of stress-induced anisotropy dominating the sonic data. We have developed a new technique for estimating the maximum horizontal SH, and minimum horizontal Sh stress magnitudes using multi-frequency inversion of wideband cross-dipole dispersions. At the mid-point of sand A, we estimate the overburden stress SV=-2278 psi; the maximum horizontal stress SH=-1843; and minimum horizontal stress Sh=-1698. The fast shear direction is NW5 in this depth interval. Radial profiling of formation shear velocity indicates varying degrees of mechanical alteration extending from one to two borehole diameters in the entire depth.
A second clean sand interval B, 300 ft above sand A, shows dipole shear anisotropy on the order of 10%. However, cross-dipole dispersions appear to merge together at high frequencies instead of showing a cross-over. Radial profiling of shear velocity in the two orthogonal directions confirms mechanical damage extending to about 2x the borehole diameter. The near-wellbore region in this interval appears to have deformed (material creep) in an attempt to reduce shear stresses and attain hydrostatic equilibrium. Using the same stress sensitivity coefficients as estimated in the lower sand A, the differential stress (SH-Sh) is estimated to be about 20% larger in the upper interval, than the corresponding value in the lower interval.
The fast-shear direction varies abruptly across the angular unconformity, changing from NW5 to NW75. Below the unconformity, this section exhibits beds with dips ranging from 10° to 30°. Cross-dipole dispersions show significant anisotropy and are non-intersecting at higher frequencies. Non-intersecting dispersions indicate bedding-induced anisotropy dominating the cross-dipole data. We have inverted borehole sonic velocities for four combinations of the TI-shale anisotropy, which can be combined with walk away VSPs to obtain all the shale anisotropy constants. These constants are needed in generating synthetic AVO gathers in anisotropic shale formations. Quantitative estimates of the radial extent of near-wellbore damage in this well suggest that perforations should penetrate deeper than twice the borehole diameter to avoid potential permeability impairment caused by near-wellbore mechanical damage.
Forties CO2 IOR Evaluation Integrating Finite Difference and Streamline Simulation Techniques
Authors: Turan Halil , Skinner Roger , Brand Peter , MacDonald Chris , Grinestaff George , Trythall Robert 
Published: December 2007

Abstract
In September 2000 the Forties Field celebrated 25 years of production. Recovery up to this point is approximately 60% of the original oil in place. The field contains undersaturated oil and is being developed under waterflood. A screening study of Increased Oil Recovery (IOR) options highlighted CO2 injection as technically feasible, suggesting an additional recovery of in the range 5-10% of the initial oil in place (STOIIP), subject to further work on the investment economics of the project and corporate sanction. This paper describes the study of the CO2 injection scheme with a focus on the reservoir simulation workflow.
Various techniques for evaluating the full field benefits of IOR schemes can be used including the Todd and Longstaff approach1 or a coarsely gridded conventional compositional reservoir simulation model. The evaluation presented in this paper builds upon a technique that incorporates detailed conventional simulation results into a full field streamline front-tracking simulation. This method was originally developed by Arco and has been successfully applied in several Alaskan oil fields2.
The technique captures the complex physics of the IOR process through fine scale, 3D, compositional, finite difference simulations of ‘type’ sections of the reservoir (the original method used 2D simulations). Results from these simulations are then used to calibrate ‘recovery’ curves that capture characteristics of oil mobilisation and returned solvent volumes as a function of gas injected. The calibrated curves representing gas injection response are then applied as tracers using streamline front tracking simulation to scale up to full field response.
Data Mining Techniques For Optimizing Fast Track Re-engineering of Mature Fields
Authors: Coste J.-F. , Valois J.-P. , Mouret Cl. , Guittard M. , Baleix J.-M. , Larrouquet F. , Mastin E. , Daniel O. 
Published: December 2007

Abstract
Mature fields have a long production history file, and many other large data sets (static data, pressure, and so on). The challenge is often to select the most promising object (a field in a block, a reservoir in a multilayered field, or an area in a wide field). We present a global approach to solve this difficulty, that uses the concepts of Data Mining. It involves Sampling (gather the data, validate, and select the appropriate level of detail), Exploration (using a large set of graphical tools), Data Management (for production data, extracting production indicators), Modelisation (using for instance the hyperbolic oil production decline equation), and Aid to final decision.
All along, graphical tools and multivariate statistical analysis are widely used and must be carefully designed. The whole of the approach requires a good geological and reservoir experience and a Reservoir and Geological Synthesis (RGS). Three field cases illustrate this fast track approach.
A New Data Integration and Work Process System for Providing Online Real-Time Drilling Collaboration
Authors: Kaminiski Dean H. , Pellerin Nicholas M. , Williams Jevon H. 
Published: December 2007

Abstract
Drilling exploration wells in deepwater or other frontier environments is an inherently expensive process. The effects of non-productive time caused by bad or less informed decisions are magnified in such costly and difficult environments.
A major operator is using the communications, presentation software, and other real-time technologies to build a more effective collaborative team to support its deepwater exploration program in the Gulf of Mexico. The technology to remotely monitor drilling operations has long existed. From its inception, the goal of this Real-Time Operations Center (RTOC) has been to move beyond mere monitoring to participation in the drilling operation.
A team of drilling experts, with an average experience level of 20+ years, was assembled. They were given the tools and facility to have 24/7 contact and visibility with all drilling operations. Additionally, the prospect teams associated with each project began holding their meetings in the Real-Time Operations Center, involving both the rig (via video conferencing) and the expert team in ongoing planning and operational decisions. The shift from the old paradigm of a reactive team gathering to sort out existing problems, to a proactive team focusing on preventing problems has had a major impact on drilling operations.
This paper will describe the technology, people, and processes employed to build this Real-Time Operations Center. The layout of the control room and the integration of the data collection and control/decision making processes will be discussed. The skills required and work processes designed to avoid a feared "big brother" syndrome are described. These steps were taken to overcome people and process issues that can defeat such an initiative. Communication and decision making procedures were outlined, designed, and implemented to facilitate success. Success and the documented value of this project are described.
Integrating 4D Seismic to Optimize Production
Authors: Staples Rob , Hague Paul , Cooke Graham , Ashton Peter , Stammeijer Jan , Jolley Steve , Stevens Tim , Marshall John 
Published: December 2007

Abstract
4D or time-lapse seismic methods have been proven by Shell and many other companies to be a valuable tool for reservoir monitoring and management1–4. In this paper, we use case studies to describe best practise. The main example is a mature field in the Northern North Sea, where continuous drilling of infill wells for two years has, so far, confirmed.the interpretation of remaining oil distribution from the 4D seismic data. In mature fields, where infill wells and sidetracks are targetted at small remaining volumes (where partial water flooding may have occurred), it becomes very important to achieve a good integration of 3D and 4D seismic data with the static and dynamic model. This is achieved qualitatively using new visualisation tools, and quantitatively using simple modelling methods such as 4D wedge modelling or more complex methods such as the generation of full field synthetic seismic. The updating of the reservoir simulator is performed in greater detail with the objective that the prediction remains accurate further into the future. This allows more reliable well targetting years after the acquisition of a 4D monitor survey, thereby reducing the necessary frequency of monitor survey acquisition.
Reserve Analysis for Tight Gas
Authors: Cox Stuart A. , Gilbert John V. , Sutton Robert P. , Stoltz Ronald P. 
Published: December 2007

Abstract
Tight gas reservoirs present unique challenges to the reservoir engineer. Applying classical reservoir engineering techniques to these reservoirs is problematic due to the length of time required to reach pseudo-steady state flow and/or establish a constant drainage area. This leads to an inability to accurately estimate the recoverable reserves in a timely and consistent manner. This paper focuses on reserve estimation techniques for tight gas reservoirs.
Both decline curves and material balance methods were found to have serious drawbacks when applied to tight gas reservoirs that had not established a constant drainage area. Gas production analysis (GPA) utilizing a combination of the decline curves and material balance in conjunction with classical pressure transient analysis was found to be more accurate in determining reserves.
Evolving New Stimulation Process Proves Highly Effective in Level 1 Dual-Lateral Completion
Authors: McDaniel B. W. , Surjaatmadja Jim B. , Lockwood Larry , Sutherland Rod L. 
Published: December 2007

Abstract
Key Production Co. began using short-radius, moderate length openhole horizontal lateral recompletions in re-entries of wells in a limestone/dolomite reservoir in northwest Texas. They found that a few wells needed some type of stimulation to achieve optimum production rates. A dual lateral (90° opposed) was drilled on one re-entry to improve production performance. This well was in an area of the field with below-average reservoir quality, and production rates were still disappointing even with two lateral sections. Fracture acidizing was the most likely method to achieve the degree of stimulation needed. There was concern that this might lead to unwanted communication with the aquifer zone below the oil column. Conventional stimulation methods could not achieve multiple, well-spaced, limited-sized fractures.
The operator used a new hydrajet-fracturing technology that has shown a very high success rate in other areas to achieve the stimulation needed for this well, and at acceptable cost. Six separate fractures were placed at selected locations along each of the two lateral sections (12 distinct fractures) in less than 8 hours from first pumping to final displacement. The resulting production rates far exceeded the operator's expectations. This paper presents a brief review of the hydrajet-fracturing stimulation process and specific details related to its highly successful application in this Level 1 dual-lateral completion.
Characterization of Partially Sealing Faults from Pressure Transient Data: An Artificial Neural Network Approach
Authors: Aydinoglu G. , Bhat M. , Ertekin T. 
Published: December 2007

Abstract
Well testing is an effective and convenient tool for characterizing the hydrocarbon reservoirs. Although, the forward solution part of the well testing theory is well advanced, the corresponding inverse solution protocols especially for the complex domains are not well established. In this paper, a new inverse solution methodology, which utilizes the artificial neural network technology in analyzing the pressure transient data, is presented. The proposed methodology is applied towards analyzing the pressure transient data collected from an anisotropic faulted reservoir. The network development begins with a simple system and the level of complexity of the system is increased as the investigation progresses. The final goals of the analysis include determination of the principal permeability values, porosity of the reservoir, distance to the fault, orientation of the fault with respect to the flow directions and the sealing characteristics of the fault. The primary goal of this work is to test the capability of the ANN methodology as an engineering tool in pressure transient analysis applications.
Computational Fluid Dynamics (CFD) as a Tool to Study Cutting Transport in Wellbores
Authors: Bilgesu H. I. , Ali M. W. , Aminian K. , Ameri S. 
Published: December 2007

Abstract
In a drilling operation hole cleaning plays an important role. Improper hole cleaning can lead to problems like reduced penetration rate, torque and drag increase, and increase in pipe sticking potential. Cutting transport in a wellbore is a complex problem affected by several parameters such as mud density, cutting size and density, rate of penetration and mud circulation rate. Researchers conducted experiments with different setups representing annulus flow in a limited number of hole sizes to investigate the contribution of several physical and operating conditions. Due to time and cost involved in the construction and conduction of the experiments all reported studies are limited to physical model dimensions and operating parameters.
In this study, we introduced a new approach to determine the parameters affecting cutting transport in any wellbore. This method utilizes a Computational Fluid Dynamics (CFD) software program. The effectiveness of selected program was determined by simulating successfully results from an experiment reported in literature.
Presented in this study are the effects of cutting and mud properties on the cutting transport efficiency for vertical and horizontal wellbores. This approach eliminates the need for expensive laboratory setups and can be used to study unlimited number of physical and operational conditions in any wellbore.