bluuebunny/crossref_metadata_2025_split huggingface dataset:
Dynamic Depth Correction to Reduce Depth Uncertainty and Improve MWD/LWD Log Quality
Authors: Dashevskiy D. , Dahl T. , Brooks A. G. , Zurcher D. , Lofts J. C. , Dankers S. 
Published: December 2007

Abstract
Accuracy of MWD/LWD depth measurements can be improved by considering the dynamic variation in drillstring length due to pipe loading under changing drilling conditions. This paper details a new method which uses surface torque, hookload and temperature measurements to determine force distribution in a drillstring and to compute apparent drillstring length. When available, torque, WOB and temperature measured downhole are used to increase accuracy and robustness of the method.
Although logging depth is referred to as a measurement, in reality only the drilling block position is measured. Depth is inferred from it using drillstring length. In recent publications physical phenomena affecting this were analyzed and quantified. Elastic pipe stretch and thermal expansion were found to be most significant. Techniques to compensate for these effects based on empirical formulae have been proposed1, but they provide an averaged correction which has insufficient accuracy for many drilling and formation evaluation applications.
This paper presents experiments covering various wellbore profiles, temperature profiles, and drilling modes. They show that the depth fluctuation may be as much as 2.7 meters with a 7000 meter long drill string even when only the current rig operation mode changes. Among other factors considered in the paper, apparent depth fluctuation is the most significant contributor to commonly observed MWD/LWD log discrepancies when bed boundaries or other features are not logged at the same depth with each sensor. These errors lead to inaccurate petrophysical calculations, distortion of borehole images, and lost time due to depth matching. Case studies illustrate the positive effect of dynamic depth correction on formation evaluation log quality.
The proposed method will improve depth measurement accuracy. This will in turn reduce the uncertainty in computation of reservoir characterization parameters such as net-to-gross and structural dip, especially when data from multiple wells are evaluated together.
Universal Process for Benchmarking Drilling-Fluid Performance
Authors: Zamora M. , McGlaughlin J. 
Published: December 2007

Abstract
A process has been developed to evaluate drilling fluid cost performance for a wide range of planning, intervention, and quality improvement activities. Meant to be universally applicable, the innovative process permits comparisons among similar and dissimilar wells drilled in the same or different global regions. It also can be used to contrast drilling fluid cost performance with operator-driven quality indicators, to classify wells for front-end loading requirements for planning, and to monitor actual-versus-planned performance during drilling.
Methods normally used for benchmarking drilling performance are not well suited for drilling fluids. The approach introduced in this paper is based on a simple ratio that compares mud cost of a well to a corresponding technical limit. The technical-limit relationship, which uses a profile index to characterize well complexity, was derived empirically from a large internal database representing a wide assortment of well types, drilling conditions, and locations.
This paper describes the development and implementation of this process. Several case studies are presented to demonstrate specific applications. Although the process was developed strictly for internal use, full implementation details are provided to encourage its use by others in the industry involved with service-quality initiatives.
Undersaturated Oil Viscosity Correlation for Adverse Conditions
Authors: Bergman D. F. , Sutton Robert P. 
Published: December 2007

AbstractThe determination of viscosity is required for evaluation of the pressure drop resulting from flow through porous media, tubing or pipelines. Viscosity is a necessary property to ascertain well productivity or to properly size tubing, pipelines and pumps. Numerous methods exist to estimate viscosity for computer calculations. Oils encountered in deep water environments are often highly undersaturated - in some cases in excess of 15,000 psi. For transport, the dead oil must be pumped in an environment with temperatures as low as 35°F. At this temperature, the dead oil atmospheric viscosity can be in excess of 500 cp. The pressure required to pump oil through pipelines from deep water can exceed 3000 psi at the pump on the platform and over 5000 psi at the sea floor. The pressure effect on viscosity results in a significant additional increase in this property which can adversely affect pipeline performance. The existing methods for estimating undersaturated viscosity were not developed using data that encompasses the pressure or viscosity range that are currently encountered by the industry. A large database comprised of 1,399 oils and 10,248 data points was constructed to evaluate the accuracy of existing correlation methods. Pressure differentials up to 25,000 psi and viscosity in excess of 1000 cp are included in the database to ensure that viscosity at both typical conditions and the extreme conditions encountered in deep water are represented. The existing methods are shown to be inadequate over this wide range of conditions. A new method was developed that offers improved accuracy and consistency over the expanded range of viscosity and pressure differential.
Evaluation of Horizontal Wells Using LWD Propagation Resistivity and Laterolog-Type Resistivity Logs
Authors: Hu G. , Bittar M. , Hou J. 
Published: December 2007

Abstract
Today, highly deviated and horizontal wells are commonly drilled for better drainage of oil reservoirs. Evaluation of horizontal wells is a challenging task. Traditionally, propagation LWD resistivity logs were interpreted with simplified models. These interpretation methods included using charts, databases, and fast inversion or deconvolution algorithms for resolution enhancement. Many of these traditional methods have limitations in evaluating horizontal wells, particularly when fresh mud is used and borehole size is enlarged. Under these difficult conditions, additional information regarding the formation around borehole will help to reduce the uncertainties in formation evaluation.
Theoretical study has shown that a particular LWD laterolog type tool, known as a "toroidal type" LWD resistivity tool, brings in additional information with significant bearing on practical formation evaluation. The additional information makes it possible in horizontal wells to study formation anisotropy and invasion effects with greater confidence.
This paper briefly introduces the operating physics of the two types of LWD resistivity tools (propagation vs. toroidal). The paper also introduces the modeling methods we have developed. Limitations and advantages of propagation phase resistivity and laterolog type focused resistivity are studied in a horizontal well drilled with fresh mud. Conventionally, when relative dip angle between borehole and formation exceeds 80 degrees, this well can be regarded as a horizontal well.
We will show how the combination of the two types of resistivity tools facilitates horizontal well evaluation in wells drilled with fresh or salty mud.
Investigation of Gas Carryover With a Downward Liquid Flow
Authors: Sutton R. P. , Skinner T. K. , Christiansen R. L. , Wilson B. L. 
Published: December 2007

Abstract
An investigation into gas carryover resulting from the downward flow of water was conducted. Water accumulation in a gas well is responsible for well productivity decline and left untreated will eventually result in the well loading up and ceasing to produce. Submersible pumps offer a viable means of removing water from the well; however, gas interference can significantly degrade pump performance and even result in pump failure. An effective means of mitigating this problem is to place the pump below the producing interval effectively allowing gravity to separate gas and water. The rule of thumb in this instance is to limit the downward liquid velocity to values less than 0.5 ft/sec to ensure gas/water separation. High steel prices dictate smaller casing strings be utilized where possible in order to enhance project economics in operations such as coal bed methane. However, smaller pipe sizes result in higher flow velocities for a corresponding surface flow rate. These higher flow velocities reduce separation efficiency, which could jeopardize project success. In order to quantify the relationship between gas carryover and liquid velocity, a full-scale model was built and actual gas carryover rates were measured. Two sizes of annular flow geometries representative of those used in the field were used in the test. The results were also confirmed with separate measurements taken from a test-well facility. These studies show the traditional rule of thumb value of 0.5 ft/sec to be conservative. Multiphase flow pattern maps were also integrated into the study as supplemental aid into development of operation guidelines and to add insight into operational practices of submersible pumps. As a result of this work, smaller casing sizes were successfully used resulting in substantial project cost savings.
An Accurate Method for Determining Oil PVT Properties Using the Standing-Katz Gas Z Factor Chart
Authors: Sutton R. P. 
Published: December 2007

Abstract
An accurate technique for estimating oil PVT properties using the Standing-Katz Z factor chart has been developed. Prior work to derive tuned gas pseudo-critical property values which provide consistent and accurate compressibility factors has been extended to oils.
Data from 1,099 worldwide oil PVT reports with 11,960 density measurements has been analyzed. The oils studied have API gravities ranging 10.6-63 with gas-oil ratios ranging 5-4,631 scf/STB. Bubblepoint formation volume factors range from 0.98-4.58 Bbl/STB. Saturation pressures ranged from 60-10,326 psia at temperatures ranging 50-332 °F with pressure differentials to 18,491 psi.
The resulting work shows that oil pseudo-critical properties can be correlated with molecular weight as with gases. The resulting relationships can be used to accurately determine saturated and undersaturated oil density. Oil PVT properties such as formation volume factor and isothermal compressibility can then be derived from fundamental relationships with density.
Since the new method correlates properties with the molecular weight of the wellstream, the chemical nature of the oil (ie naphthenic, paraffinic, etc) is considered. Existing correlations (30 for bubblepoint oil formation volume factor and 17 for isothermal compressibility) have been identified in the literature. These methods are tested against the database along with the new method to determine accuracy and recommended procedures. Isothermal oil compressibility has historically proved difficult to correlate with errors typically in excess of 30%. The proposed method significantly reduces the error in calculated isothermal compressibility when compared with traditional methods.
Production Increases at PDVSA Using an Improved SRP Control
Authors: Peterson R. , Smigura T. , Brunings C. , Quijada W. , Gomez A. 
Published: December 2007

Abstract
Sucker Rod Pumping (SRP) systems have used various control methods to optimize production, improve energy efficiency, and reduce maintenance. These systems typically use Rod Pump Controllers (RPCs) or timers to cycle the rod pumping unit on and off. Variable Speed Drives (VSDs) are occasionally used in conjunction with RPCs to improve operation by modulating pump speed. An improved SRP control that combines the RPC and VSD functions in an integrated system was installed on approximately 100 rod pumping systems at PDVSA starting in January 2004. The improved control resulted in a median production increase of 21%.
Embedded optimization controls in the VSD allow PDVSA engineers to preset a desired target pump fill based upon an Optimizer ID routine that samples production rates at various operating speeds and pump fill values over several days. The control subsequently adaptively modulates the pumping speed profile accordingly, thereby maintaining continuous operation at the identified optimal target pump fill. By maintaining a constant fluid level rather than the traditional cycling of fluid level between two limits, production losses associated with cycling above the target IPR well flowing pressure are eliminated. Furthermore, continuous and adaptive downhole pump speed control within each stroke allows the target IPR well flowing pressure to be reduced while improving equipment protection.
In addition, the VSD exercises the pump through controlled sequences that automatically identify other valuable system characteristics such as pump leakage, traveling/standing valve problems, pumping unit characteristics, counterbalance characteristics, and motor electrical parameters.
Modeling Transient Thermo-Poroelastic Effects on 3D Wellbore Stability
Authors: Farahani H. S. , Yu M. , Miska S. , Takach N. , Chen G. 
Published: December 2007

Abstract
The temperature difference between the wellbore drilling mud and the formation, especially in deep wells, causes volumetric expansion of pore fluid and rock matrix. Most existing models ignore the effect of convective heat transfer, which is a valid assumption for low permeability formations such as shales. However, convection plays an important role in controlling wellbore stability in high permeability formations such as sandstones.
A 3-D thermo-poroelastic model that accounts for the effect of convective heat transfer is developed in this study. Transient coupled pore pressure and temperature equations for non-isothermal conditions are developed based on conservation laws.
Thermal effects are generated by the temperature imbalance between the drilling fluid and drilled formations, and increase as the temperature imbalance increases. Cooling the formation is found to be helpful in lowering collapse pressure, resulting in a more stable borehole. However, it is also found that a formation is more vulnerable to fracture because cooling also lowers the breakdown pressure. A higher mud weight is required to fracture the formation when hot drilling fluid is used because hotter fluids increase the breakdown pressure. Also, a higher mud density is needed to prevent a wellbore from collapsing when a hotter fluid is being circulated through it.
The model presented in this study is useful for wellbore stability analysis for deep wells and deep water applications where mud temperature varies significantly along the well path.
Achieving Savings in Time-Sensitive Completion Costs: Results from Recent Single-Trip Multizone Frac-Packing Case Histories
Authors: Van Sickle E. , Womble A. , McKown M. 
Published: December 2007

Abstract
With rig costs and other time-sensitive completion costs rising, offshore operators must continually find ways to reduce operating costs while minimizing risk. Frac packing often involves expensive fluids, proppant and equipment. Single-trip multi-zone sand control completion systems are not new to the Gulf of Mexico, but the adaptation of these systems to facilitate frac packing has created new opportunities for the technology. Multi-zone, single-trip completion systems were first used offshore California in the 1980s to reduce completion costs in marginal fields. The initial system design was used successfully in several hundred wells to complete more than 900 zones. In the early 1990s, the system was modified to minimize rig time and reduce formation damage in the Gulf of Mexico by reducing formation exposure time to completion fluids. This paper will review the history of multi-zone, single-trip completion systems and discuss how the systems were adapted to facilitate frac packing, including modifications to allow for high pump rates and large sand or proppant volumes. The paper will also present detailed results of recent applications for several Gulf of Mexico operators that demonstrate the advantages of the technology over more conventional stack-pack completion methods.
The Application of Artificial Neural Networks With Small Data Sets: An Example for Analysis of Fracture Spacing in the Lisburne Formation, Northeastern Alaska
Authors: Kaviani D. , Bui T. D. , Jensen J. L. , Hanks C. L. 
Published: December 2007

Abstract
Artificial neural networks (ANNs) have been widely used for prediction and classification problems. In particular, many methods for building ANNs have appeared in the last two decades. One of the continuing important limitations of using ANNs, however, is their poor ability in analyzing small data sets because of overfitting. Several methods have been proposed in the literature to overcome this problem. Based on our study, radial basis functions (RBF) with stacked generalization can effectively decrease the error of the prediction when there is an underlying relationship between the variables. We have applied this method to determine the factors controlling and related to fracture spacing in the Lisburne Formation.
Comparing our results with those from other ANN methods, we find that the proposed method gives a substantially smaller error than alternative methods. The errors in predicted fracture spacing for the Lisburne using the conventional ANN methods are about 50 to 200% larger than those obtained using the proposed method. By having a method which predicts fracture spacing more accurately, we were able to more reliably identify the effects of such factors as bed thickness, lithology, structural position, and degree of folding on the spacing.
In petroleum engineering and geosciences, there are many cases where the number of data is limited because of expense or logistical limitations, e.g., limited core, poor borehole conditions, or restricted logging suites. Thus, the methods used in this study should be attractive in many petroleum engineering contexts where complex, non-linear relationships need to be modeled using small datasets.
Automated Reporting Using Rig Sensor Data Enables Superior Drilling-Project Management
Authors: Thonhauser G. , Mathis W. 
Published: December 2007

Abstract
An integrated process management system is the key to success of an enterprise working in the exploration business. Classic project management consists of the creation of an expectation, the well plan, appropriate process monitoring and the post analysis of the project through the comparison of the expectation and the actual process. As a result of the post analysis lessons learned are compiled.
The quality of this traditional project management is strongly dependent on information flow. State-of-the-art reporting on a drilling rig is recurrent human reporting such as the classic morning report, although there are a lot more sources of information available.
The presented concept of automated reporting, away from human observations, is ensured by utilizing rig sensor data. The automated reporting provides management, engineering and operations with the level of detail and granularity of objective, high quality information they need. It also offers the possibility of knowledge management and exchange at the same organizational level providing different "views" of the same project. This means that operations receive information on detailed process parameters, engineering on essential design variables for future wells and management on cost. Along with traditional project management this new automated reporting enables continuous, real-time project tracking and analysis even with a declining workforce because all information is bundled and under "central control".
Automated reporting is able to cover the life-cycle of every well construction and allows the establishment of high quality benchmarks for future planning and project evaluation in realtime. Moreover, it enhances the learning and experience level of every single person involved in the process.
Finally, it offers the possibility to manage multiple concurrent projects such as a company's fleet of drilling rigs to be able to optimize resource allocation and project economics.
Real-Time Reservoir Surveillance Utilizing Permanent Downhole Pressures—An Operator's Experience
Authors: Chorneyko D. M. 
Published: December 2007

Abstract
Permanent downhole pressure gauges supply important information for reservoir surveillance and management. Technology has evolved over the more than 40 years since the first installation. Service companies have made significant improvements to the components of a permanent downhole gauge installation for a well. The components include gauges, housing, cable, connections, and acquisition systems. Installation and use of these gauges has become routine in many situations because of the improved reliability and the value of information that the gauges provide.
Pressures from permanent downhole gauges can be examined almost as soon as they are acquired, depending on communication speed. The data is used for many applications including pressure monitoring, interference testing, water and gas injection monitoring, transient well testing, evaluation of well performance, reducing the flowback time of new wells, monitoring hydraulic fracturing operations, and monitoring pump inlet and outlet pressures for pumping wells.
On the practical side, there are issues associated with the data that these gauges collect. Vast amounts of data are being gathered continuously at intervals down to one second over numbers of years. This data must be communicated from the well to the office. Since the data is an asset, it must be stored and archived. Individuals require access to the data at different times, for different reasons, and at differing resolutions. Interpretation of the data poses new challenges as there is more hidden in the long term pressure record than just a collection of drawdowns and buildups. The data contains information about parameters changing during short and long time intervals both near the well and in the reservoir. As more and more permanent downhole gauges are deployed, maximizing the corporate benefits becomes an asset management issue. Companies are faced with stewardship of the investment, communicating learnings across the organization, developing or acquiring software tools for data management and analysis, proposing and supporting industry- wide standards for consistent data capture and communication, and integrating data into work processes and into applications such as smart wells and smart fields.