bluuebunny/crossref_metadata_2025_split huggingface dataset:
Predicting and Preventing Wellbore Instability Using the Latest Drilling and Logging Technologies: Tullich Field Development, North Sea
Authors: Russell K. A. , Ayan C. , Hart N. J. , Rodriguez J. M. , Scholey H. , Sugden C. , Davidson J. K. 
Published: December 2007

AbstractInnovative geomechanical, drilling, logging and seismic techniques have been used to successfully develop a geologically complex discovery in the North Sea, Tullich field. With individual reservoir unit thicknesses below the limit of seismic resolution, and a restricted depth window for completion, optimal placement of horizontal production wells, without delays, was vital to the successful and economical development of the field. Wellbore instability was a key concern after recent drilling experience in nearby fields with similar formations. By combining efficient teamwork and the latest technologies, the complex reservoir was successfully developed, both in terms of cost savings while developing the field, and good oil production.
The Role of Electrofacies, Lithofacies, and Hydraulic Flow Units in Permeability Predictions from Well Logs: A Comparative Analysis Using Classification Trees
Authors: Perez Hector H. , Datta-Gupta Akhil , Mishra S. 
Published: December 2007

Abstract
Predicting permeability from well logs typically involves classification of the well log response into relatively homogeneous subgroups based on either electrofacies, lithofacies or hydraulic flow units (HFU). The electrofacies-based classification involves identifying clusters in the well log response that reflect "similar" minerals and lithofacies within the logged interval. The procedure is straightforward and inexpensive. However, identification of lithofacies and HFU relies on core data analysis and can be expensive and time consuming. To date, no systematic study has been performed to investigate the relative merits of the three methods in terms of their ability to predict permeability in uncored wells.
The purpose of this paper is three-fold. First, we examine the link between the three approaches using a powerful and yet intuitive statistical tool called "classification tree analysis". The tree-based method is an exploratory technique that allows for a straight-forward determination of the relative importance of the well logs in identifying electrofacies, lithofacies and HFU. Second, we use the tree-based method to propose an approach to account for missing well logs during permeability predictions. This is a common problem encountered during field applications. Our approach follows directly from the hierarchical decision tree that visually and also quantitatively illustrates the relationship between the data groupings and the individual well log response. Finally, we demonstrate the power and utility of our approach via field applications involving permeability predictions in a highly complex carbonate reservoir, the Salt Creek Field Unit (SCFU) in West Texas. The intuitive and the visual nature of the tree-classifier approach also make it a powerful tool for communication between geologists and engineers.
Reliability Assurance, Managing The Growth Of Intelligent Completion Technology
Authors: Mathieson Derek , Rogers John , Rajagopalan Shashidhar , McManus Robert 
Published: December 2007

Abstract
Since the first Intelligent Completion in 1997 over 150 installations havebeen completed by the industry as a whole. Reliability assurance is recognizedas one of the central themes for continued market stabilization and growth inthis technology sector. A detailed review of actual field performance, drawingfrom a database of over 90 installations in various operating environmentsworldwide, is presented by generic system type in context with marketperception of risk associated with this technology. The paper focuses oninterpretation of the raw field data, primary analysis tools and how theinformation generated is being used to calibrate both reliability growthprograms for the technology and value optimization strategies for fielddevelopment.
Reliability trends are charted over the 5-year period from 1997, providing astatus check for both current and future expectations in system performance. Inaddition the paper describes the importance of both sub-system and architecturereliability and how these concepts, when calibrated with field performancedata, are being used to build realistic models for system reliabilityprediction and valuation risk analysis.
Voidage Replacement Ratio Calculations in Retrograde Condensate to Volatile Oil Reservoirs Undergoing EOR Processes
Authors: Clark Robert A. , Ludolph Brian 
Published: December 2007

AbstractVoidage replacement ratio (VRR) is commonly used to measure the rate of change in reservoir energy. VRR optimization is often an important factor in planning and managing enhanced oil recovery (EOR) projects. VRR is easily calculated in black oil waterflooding operations. However, in reservoirs impacted significantly by compositional effects, calculation of VRR is nontrivial.A reservoir that grades from retrograde condensate to volatile oil presents tremendous difficulties in determining VRR. The large vertical relief and associated steep compositional gradients commonly present in thrust belt regions further exacerbates this problem. An excellent example of this problem is the high-pressure miscible gas injection project in Boquerón Field (El Furrial Trend in Venezuela). At Boquerón, the saturation pressure varies with depth from 7,700 psia to 3,300 psia.Typically, an equation of state (EOS) is constructed to model the phase behavior variability in compositional systems. In compartmentalized reservoirs, the initial composition can also vary areally. However, neither EOS programs nor typical compositional numerical models calculate and/or report VRR.This paper presents a method (developed for Boquerón Field) to compute VRR for compositional systems using a compositional full field model (CFFM) and an EOS program. The field is broken up into major pressure compartments in the model. Regional compositions, pressures, injection gas volumes (surface units), and volumes-in-place (reservoir barrels) are extracted from the model output at each time step. An EOS program is used to compute the surface quantity of injection gas theoretically required to maintain constant pressure. This quantity is used, in conjunction with the amount of gas actually injected, to calculate VRR for each region and time step. The numerical simulator can be updated on a regular basis and used as a surveillance tool to monitor reservoir energy changes and to satisfy regulatory reporting requirements. It is also used as an optimization tool to manage EOR operations.
Pressure-Transient Responses of Horizontal and Curved Wells in Anticlines and Domes
Authors: Al-Mohannadi N. , Ozkan E. , Kazemi H. 
Published: December 2007

AbstractThis paper presents a discussion of the pressure-transient responses of horizontal wells in anticlinal structures and curved wells in flat reservoirs. It is shown that, in the absence of gas cap, conventional horizontal-well models may be used to approximate the flow characteristics of the systems where the trajectory of the well does not conform to the curvature of the producing structure. If a gas cap is present, however, the unconformity of the well trajectory and producing layer manifests itself especially on derivative characteristics when the gas saturation increases around the well. In general, the most significant deviations from the conventional horizontal-well behavior are observed during the buildup periods following long drawdowns. In these cases, the pressure-transient analysis is complicated and requires detailed numerical modeling of the well and reservoir curvature in the vertical plane.
Monitoring Horizontal Producers and Injectors During Cleanup and Production Using Fiber-Optic-Distributed Temperature Measurements
Authors: Brown G. , Storer D. , McAllister K. , al-Asimi M. , Raghavan K. 
Published: December 2007

Abstract
This paper describes the application of fiber-optic-distributed temperature systems installed in several long horizontal open-hole completion intervals of production and injection wells in Oman. We demonstrate how distributed temperature data, from both types of wells, was used to optimize completion procedures and improve knowledge of the reservoir and its performance.
The Shuaiba reservoir produces 44° API oil from a low permeability micritic lime mudstone, typically 3 md. Initially, gas injection in vertical wells was selected to enhance oil recovery, but producing wells commonly experienced gas breakthrough, gas flaring was undesirable, and surface-compression constraints were encountered. For these reasons the operator decided to phase out gas injection and use line-drive water injection from horizontal wells. Wells were drilled horizontally, with up to 5,000-ft open-hole completions, but varied in effectiveness.
Fiber-optic distributed temperature measurement systems were installed in a horizontal water injector and several horizontal oil producers during 2002 to monitor the long open-hole reservoir intervals during well startup, production, and injection. Data from the fiber optic water injector showed that the intervals flooded slowly from the heel to the toe over a period of months, giving the operator improved knowledge of reservoir sweep from this type of completion. The first oil producer exhibited slow cleanup from the heel, enabling a change in pre-production well stimulation procedures to improve cleanup.
The results demonstrate that it is possible to monitor long horizontal open hole intervals continuously, during both clean-up and production, without the need for multiple well interventions. This has proved a safe and cost effective solution to improve the operators understanding of the performance of horizontal wells drilled in the Shuaiba reservoir. Substantial savings are expected through DTS surveys, with a one-time installation costs comparable to a coiled tubing run production log. Following the installation, DTS is available to provide survey data for life of the completion. It is not only cost effective, but also data acquisition operation is much less risky.
Valhall Field: Horizontal Well Stimulations "Acid vs. Proppant" and Best Practices for Fracture Optimization
Authors: Olson Karen E. , Olsen Eivind , Haidar Sami , Boulatsel Alexandre , Brekke Kristian 
Published: December 2007

Abstract
Proppant fractures along the horizontal laterals in the Valhall Field have become a standard completion method for the last eight years with over 150 proppant fractures completed to date. The development of the flank regions of the Valhall Field began, with the first of 14 wells completions, in March 2003. Lateral lengths of up 2,000 meters will be drilled from two new platforms placed on the North and South edges of the field. The chalk formation in the flank regions is expected to be more competent then the crestal part of the field, so the question was raised as to whether fracturing should be done with acid or proppant. From a proppant fracturing perspective, each flank well will require between 10 to 14 prop fractures along its lateral requiring 2.5–3.7 Million pounds of proppant per well.
Three different methods have been used to determine whether the wells should be acid or proppant fractured. These consist of reviewing the historical well performance, analytical and numerical modeling. All three methods clearly showed proppant fracturing was the preferred stimulation for the Valhall Field regardless of it's location. Acid fracturing becomes the stimulation of choice only if the well does not come in contact with enough OOIP (e.g. 5 MMSTB) to justify the proppant fractures.
Proppant fracturing is expensive, so in conjunction with identifying the best stimulation method for the flank region, optimization with respect to fracture spacing along the horizontal lateral, fracture length and width have been numerically modeled for both the crestal and flank wells. This is an evolving process that should be considered an industry "Best Practice" as it enables real time optimization of ‘prop’ fracturing along a horizontal lateral during the drilling and completion phase. Since the start of this "Best Practice" in 2002, the wells stimulated in the crestal part of the Valhall Field have had the highest productivity in the field's history.
Fracture Design, Execution, and Evaluation in Retrograde Condensate Reservoirs: Case History of the Angsi Field, Offshore Malaysia
Authors: Murrey Michael D. , Cipolla Craig L. , Nor M. Nazri M. , Manzoor Hussain Wukar Hussain 
Published: December 2007

AbstractThis paper details the evolution of hydraulic fracture design, execution, and evaluation in the Angsi field, Offshore Malaysia. The primary target for propped hydraulic fracturing treatments is a 660 ft thick series of stacked fluvial sandstones at an average depth of 8500 ft-TVD, designated the K-sands. The K-sands are high temperature (320ºF), over-pressured retrograde gas condensate reservoirs ranging from 10 to 90 ft net thickness and 0.1 to 3 mD. Multi-staged propped hydraulic fracture treatments are required to improve well deliverability and to mitigate the detrimental effects of condensate dropout on well performance.The initial treatment screened out very early in the job. Fortunately, extensive diagnostic data were gathered to evaluate the treatment – including temperature and radioactive tracer logs, mini-fracs with real-time BHP and BHT, memory gauges that provided accurate BHP data for the propped treatment, and comprehensive fluid QC and rheology (Fann 50 on the platform). The integration of the diagnostic data with fracture modeling and engineering analyses indicated that the screen-out was caused by a combination of complex fracture growth and low fluid viscosity. The Angsi treatment strategy was subsequently changed to mitigate and control the problems associated with complex fracture growth, which included increasing fluid viscosity, using proppant slugs, and optimizing the perforation placement. The changes in treatment strategy implemented after the initial early screen-out resulted in the successful placement of 38 of the subsequent 41 treatments (93% success). Success is defined as placing 90% or more of the designed proppant volume.Fracturing operations were significantly improved with the introduction of "live annulas" fracturing after the initial well, resulting in cost savings of at least U.S. $10 million in the first year. Live annulus fracturing also provided "real-time" BHP measurement that resulted in better treatment control and evaluation. Treatment designs were continuously improved throughout the program, increasing both fracture length and conductivity and improving K-sand interval coverage. The success of the first phase of the fracturing program resulted in gas production of over 190 MMCFD initial capacity and 8,200 BCPD.
Casing Running Challenges for Extended-Reach Wells
Authors: Mason Colin J. , Lopez Jesse , Meling Sigve , Munger Robert , Fraser Barry 
Published: December 2007

AbstractRunning long production casing strings in extended-reach wells is usually recognised as one of the most critical of all well operations. Failure to reach target depth often has a profound consequence on well deliverability and overall cost. In this paper, an overview on the status of current casing running tools and techniques is given. This is complemented with an assessment of the impact of drilling technology on the ability to run casing.The systematic collection of quality data and application of consistent analysis techniques can help identify common factors associated with both casing running success and failure. Results are given, where this approach has been applied to two current extended-reach developments.
A Streamline-Based Method for Assisted History Matching Applied to an Arabian Gulf Field
Authors: Agarwal Bijan , Blunt Martin 
Published: December 2007

Abstract
We present a streamline-based history matching method that overcomes two of the major limitations of previous approaches: (1) it uses a three-phase compressible streamline simulator for the forward simulation, and so its application is not limited to incompressible waterfloods; and (2) geological constraints, such as regions of differing facies, can be honored. Permeability, porosity and anisotropy can all be modified using the methodology of Assisted History Matching.1–3 In this paper the technique is extended with suggested modifications to the reservoir description computed assuming tracer-like flow. This allows the engineer to direct the parameter changes through interactive code.
The method is applied to history matching the full field model for the Southwest Fateh Mishrif field located in an offshore concession in the Emirate of Dubai. The Southwest Fateh Mishrif is a carbonate reservoir containing a highly undersaturated oil. There are currently 42 active producers and 27 active water injectors. First production occurred in 1972 and waterflooding commenced in 1975 prior to the field average reservoir pressure falling below the bubble point with present injection rates of 320,000 BWPD.
A Deconvolution Technique Using Fast-Fourier Transforms
Authors: Cheng Yueming , Lee W. John , McVay Duane A. 
Published: December 2007

Abstract
We present a deconvolution technique based on a fast-Fourier-transform algorithm. With the new technique, we can deconvolve "noisy" pressure drawdown and buildup test pressure-time data (distorted by wellbore storage) and "noisy" rate data. The wellbore storage coefficient can be variable in the general case. In cases with no rate measurements, we use a "blind" deconvolution method to restore the pressure response free of wellbore storage distortion. Our technique detects the afterflow/unloading rate function using Fourier analysis of the observed pressure data.
The technique can unveil the early time behavior of a reservoir system masked by wellbore storage distortion and it thus provides a powerful tool to improve pressure transient test interpretation. It has the advantages of suppressing the noise in the measured data, handling the problem of variable wellbore storage, and deconvolving the pressure data without rate measurement.
We demonstrate the applicability of the method with a variety of synthetic and actual field cases for both oil and gas wells. Some of the actual cases include measured rates (which we use only for reference purposes) and others do not.
Planning and Interpreting NMR Fluid-Characterization Logs
Authors: Minh Chanh Cao , Heaton Nick , Ramamoorthy Raghu , Decoster Eric , White Jim , Junk Elmar , Eyvazzadeh Ramsin , Al-Yousef Osama , Fiorini Rosaura , McLendon Darren 
Published: December 2007

Abstract
This paper presents a logical approach to ensure successful nuclear magnetic resonance (NMR) logging for fluid-characterization purposes. Numerous examples are shown in a three-stage process consisting of a) planning, b) processing and interpretation, and c) validation and integration.
First, modeling is performed to assess the NMR contrast, using any available information concerning anticipated fluid types. Knowledge of downhole conditions also allows the estimation of the NMR signal-to-noise ratio (SNR) from which the sensitivity and statistical error can be evaluated. The outcome of the planning process is a suite of NMR pulse sequences that optimizes resolution of the different fluids and minimizes error with the shortest possible acquisition time.
Interpreting fluid-characterization NMR logs is relatively straightforward when the fluids have large NMR contrast and obey the standard correlations. However, dissolved gas, wettability variations, internal field gradients, and restricted diffusion can cause deviations from model behavior and have significant effects on NMR relaxation data. These effects need to be recognized and accounted for.
To gain insights into the NMR-based fluid evaluation process, we have developed a model-independent technique that gives various sets of D-T1-T2 maps. The maps are analogous to the crossplots commonly used in log interpretation practices and are indispensable in the interpretation of the data. We also explain quantitative interpretation techniques from D-T2 maps.
Integrating NMR fluid-characterization results with other information and openhole logs constitutes the final step. As with any technique, results need to be crosschecked with other log data for consistency. The answer gives a water saturation that can be verified with other tools and techniques such as the dielectric log, resistivity logs, and the density magnetic resonance technique method.
Comprehensive Transient Modeling of Sand Production in Horizontal Wellbores
Authors: Nouri Alireza , Vaziri Hans , Belhaj Hadi , Islam Rafiqul 
Published: December 2007

Abstract
The design of the most appropriate completion technique for a horizontal wellbore is still a formidable task. The choices are whether to opt for an openhole or a cased completion and, whether to gravel pack or there will be no need for sand production control under prospective operational conditions. This paper introduces a predictive tool that forecasts not only the initiation of sanding, but also its rate and severity in real time. All possible failure mechanisms including shear, tensile and volumetric have been included in the proposed model. Experimental data on large block tests are used to support the validity of the proposed numerical model.
A series of well-documented experiments on a large size horizontal wellbore was numerically simulated utilizing a finite difference package. The model covers the interaction between fluid flow and mechanical deformation of the medium, capturing all possible mechanisms of failure. Providing the means of encompassing the sequential nature of sanding and the direct modeling of progressive character of the cavity, the suggested model is the first to be reported using a fully coupled transient simulation approach. The removal process of the qualified elements is simulated in the model, and the criteria that are used for this process are in accordance with the physics of sand production. This numerical tool can be used to address the main factors related to sand production problem that include the conditions under which sanding takes place and how extensive if indeed it occurs.
The model shows excellent agreements with experimental results in terms of borehole deformation and sanding rates. The model predicted initiation of shear failure from the sides of the borehole and its propagation to the top and sides of the sample. Likewise, it became evident that removal of the failed material during production may trigger more sanding through development of shear failure to the formerly intact material that may continue to fail accordingly. More importantly, the agreement between the numerical and experimental well face deformation as well as sanding rate and volume suggests that an accurate prediction of sanding can be made by using the proposed numerical modeling. Therefore, a sound decision in completion selection and sand control strategy can be suggested. Avoiding unnecessary gravel packing, and other sand controlling and prevention techniques can be achieved by utilizing the proposed model, which in turn reduces the cost of well completion dramatically. In addition, the production decline due to gravel void throat block by fine movement can be prevented. A wide use of the proposed model is expected immediately in the oil industry.