bluuebunny/crossref_metadata_2025_split huggingface dataset:
Limits on Data Communication Along the Drillstring Using Acoustic Waves
Authors: Gao L. , Gardner W. , Robbins C. , Memarzadeh M. , Johnson D. 
Published: December 2007

Abstract
The first commercial acoustic telemetry system was successfully introduced in 2000 as part of a drillstem testing system. However, duplicating the success of the acoustic telemetry to environmentally challenging LWD applications at high data throughput remains a formidable task. The primary limitation arises from normal drilling operations that produce in-band acoustic noise at multiple sources at intensities comparable to the transmitter output. This noise, together with the signal attenuation along the drill string, adversely affects the data throughput. To determine the communication capacity of the drill string channel using acoustic waves, we examined the impact of channel characteristics, signal attenuation and noise in detail. Based on a communication model which incorporates the effects of both drill string acoustic channel and noise, we extensively studied the capacity of the system using the waterfilling method. For this analysis, realistic downhole transmitter power output, experimentally measured noise at the surface, and measured attenuation of acoustic waves in the drill string were used as input parameters. The results show that a typical drill string channel has a potential capacity of up to several hundred bits per second under noisy drilling conditions. Implications of the channel capacity on acoustic telemetry system designs are discussed. A communication technique that comes close to realizing a high-rate telemetry system is introduced. Methods to optimize various aspects of the system such that maximum channel utilization can be realized under drilling conditions are also discussed. Potential enhancement to data rates through application of error control coding is briefly covered.
Experimental Studies of Water Wetting in Large-Diameter Horizontal Oil/Water Pipe Flows
Authors: Cai J. , Nesic S. , Li C. , Tang X. , Ayello F. , Ivan C. , Cruz T. , Al-Khamis J. N. 
Published: December 2007

Abstract
Internal pipeline corrosion in oil production and transportation is always associated with the presence of water, and the likelihood of corrosion generally increases with the volume fraction of water. When the walls of the pipeline are wetted with oil no corrosion is possible. Highly turbulent flow was associated with negligible corrosion due to water entrainment by the flowing oil, whereas low flow rates or intermittent flow have been associated with corrosive conditions.
In this study, four advanced techniques (wall conductance probes, corrosion monitoring, wall sampling and flow pattern visualization) were used to determine phase wetting on the internal wall of pipe at different superficial oil and water velocities in the large diameter oil-water horizontal flow.
Four flow patterns were observed: stratified flow, stratified flow with mixed layer, semi-dispersed and dispersed flows.
Three types of phase wetting regimes (water wetting, intermittent wetting and oil wetting) were determined. A phase wetting map was obtained based on the overlapping information from these techniques. It is clear that the critical oil velocity of water entrainment increases with increasing input water cuts. The water cut has a significant effect on the critical oil velocity for water entrainment.
Based on the results of corrosion monitoring, it is also found out that no corrosion occurs under oil wetting. At same superficial oil velocity, corrosion rate under water wetting is much higher than that under intermittent wetting.
Automated Microseismic Event Detection and Location by Continuous Spatial Mapping
Authors: Drew J. , Leslie D. , Armstrong P. , Michaud G. 
Published: December 2007

Abstract
Optimal control of oil-field hydraulic fracturing operations will benefit from reliable, automated, real-time microseismic monitoring. Existing microseismic processing techniques are often either unreliable, or impractical for real time use.
In this paper we present the method of Coalescence Microseismic Mapping (CMMapping) for detection and localization of microseismic events. The technique is both automatic and robust, and explicitly allows for the inclusion of velocity model uncertainty into its formulation. We present the general basis for the method and illustrate its use on data acquired during a hydraulic fracture well stimulation.
Technologies Trials of Intelligent Field Implementation in Carmopolis Field
Authors: Silva M. F. , Portella R. C. M. , Izetti R. G. , Campos S. R. V. 
Published: December 2007

AbstractCarmopolis field, in the Sergipe/Alagoas Basin, located in the northeast of Brazil, is the country largest onshore oil accumulation. The reservoir is very heterogeneous and has an adverse fluid mobility ratio. During the last thirty years, waterflooding has been employed as secondary recovery method. Hence, considering waterflooding optimization as the main drive, Carmopolis field has been chosen by Petrobras as pilot project in its recently created Intelligent Field R&D Program. In the project, a wide range of technology trials is been conducted, including downhole monitoring, downhole flow-control, and artificial lift optimization. All wells in the pilot area use rod pumps and the aim of the project is to automate completely the system including smart well completions and artificial lift automation with a SCADA system, to accomplish a systematic integration of downhole measurements, communication, and control, thus improving reservoir and production management. The present paper, addresses the challenges faced in the implantation phase of the project, and discusses values and benefits in employing these technologies in an onshore mature field.
Decision Making With Uncertainty While Developing Multiple Gas/Condensate Reservoirs
Authors: Kabir C. S. , Gorell S. B. , Portillo M. E. , Cullick A. S. 
Published: December 2007

AbstractWell-developed methodology exists for handling uncertainty for a single reservoir. However, development of multiple fields presents significant challenge when uncertainty in large number of variables, such as gas-in place and liquid yield, occur in each reservoir. Some of the challenges stem from our need to forecast the system behavior involving a coupled reservoir/wellbore/surface (CRWS) network for the entire spectrum of variables so that facilities can be designed for the range of fluid composition and throughput. Of course, assessing well count and sequencing well drills are some of the important objectives.This paper describes probabilistic production forecasting with a compositional CRWS network model for nine reservoirs involved in delivering gas supply to a LNG plant in Nigeria. Our main objective was to use an economic indicator to select optimal design of two main pipelines, each transporting 200 and 300 MMscf/D from the two production platforms, located 15- and 5-km, respectively, from the processing platform.Rate and cumulative profiles showed that sustained deliverability of gas can be realized for about 11 years before the decline occurred in high-permeability reservoirs. In other words, uncertainty in gas-in-place did not surface during the plateau period, only during the decline period lasting another five years, after the first eleven. In contrast, the liquid rates exhibited large uncertainty band throughout, a direct manifestation of the condensate yield issue. The uncertainty band among each of the 12 components aided facilities design. Differences in net present value (NPV) and discounted profitability index (DPI) were used as discriminators for discerning optimal pipe size from the standpoint of project economics.
Diagnostic Pumping Tests to Optimize Fracturing Designs in the Harsh Environment of Western Siberia
Authors: Manrique J. F. , Winkler A. , Guglielmo D. , Pongratz R. 
Published: December 2007

Abstract
Hydraulic proppant fracturing continues to rapidly evolve in western Siberia/Russia and is seen as the most important and effective means to improve oil production from existing, as well as, newly drilled wells.
Fracture treatments in Russia were traditionally small, conservative treatments with small-sized proppants and inefficient fracturing fluids. They were designed with a one-size-fits-all approach to bypass near-wellbore damage rather than provide sustained and optimum productivity. Results were acceptable for the economic models existing at that time. However, the competitive environment, production targets, and financial goals of oil-producing companies today require a change in approach.
Optimization of hydraulic-fracturing treatments soon became a necessity and resulted in a design methodology aimed at improving the production performance rather than simple modification of pumping schedules. Designing for performance required a change in tactics and an optimization mentality to achieve step-change results.1,2
Production analysis suggested radical changes in fluids, breakers, job sizes, types, and tonnage of proppant, etc. In this paper, we discuss and compare the evolution of the stimulation practices and implementation of technology that matched performance to fracture design. We describe some of the steps and practical standards implemented to improve the performance of hydraulically induced fractures.
In particular, we discuss the critical importance of the minifrac diagnostics used intensively and extensively as a powerful diagnostic procedure. The diagnostic procedure became the most useful and practical tool for fracture placement and successful execution of larger fracture treatment designs with larger proppant sizes, perforating strategy, redesign of fracturing treatments on location, and continuous improvement of treatment designs and placement. The paper will examine the different pumping diagnostics performed in western Siberia and some of the reoccurring results observed. It also evaluates the consistency and specific problems encountered working around the traditional completion and operational practices in West Siberia, and best practices for performing a minifrac during extreme cold.
A Fundamental Model for Prediction of Hole Curvature and Build Rates with Steerable Bottomhole Assemblies
Authors: Pastusek P. , Brackin V. , Lutes P. 
Published: December 2007

ABSTRACT
There are four key technical issues to be addressed when drilling directional wells with steerable bits and bottom hole assemblies: maximizing hole quality, addressing tool face control, eliminating bit and assembly vibration, and predicting hole curvature or build rates. Hole quality1 and tool face control2-7 have been covered in several previous SPE papers, as has bit and assembly vibration elimination8-9. This paper covers the recent development of a fundamental model for the prediction of hole curvature based on measured bit response and modeled bottom hole assembly behavior.
Bit side cutting is a nonlinear function of side force, gauge design, rotary speed, rate of penetration, rock strength, and cutter dull state. To characterize the bit's side cutting response, a series of tests are run in a full scale drilling simulator10 under a variety of drilling parameters and sideloads. Axial and lateral bit trajectories are measured and a response curve is generated. The bit side cutting angle measured in the lab, is equivalent to bit tilt calculated on a bottom hole assembly (BHA). Several hundred tests have been run to measure the response of numerous bits. These response curves are then used to relate bit performance to BHA response.
The BHA is modeled with a finite element analysis program over the range of hole curvatures and tool settings which define the operating envelope for the tool. The result of the analysis is a bit side force to bit tilt response surface for the tool over its operating range. The response curve for the bit and the response surface for the BHA are then plotted on the same set of axes. The intersection of the two graphs represents the steady state response of the system and is used to predict the achievable hole curvature of the bit-BHA system. This work shows that bits often selected for rotary steerable systems are more laterally aggressive than required of the BHA to achieve the desired hole curvature.
The model has been verified with full scale field tests. While this work was originally developed for PDC bits and rotary steerable systems, the fundamental model can be applied to all types of bits and drilling systems. It has also been applied to motor and vertical drilling systems with PDC and Impregnated bits.
Service Line Option for Hydrate Management in Single Flowline Tieback
Authors: Patni S. , Davalath J. 
Published: December 2007

Abstract
Many subsea projects worldwide would benefit technically and commercially from using a single flowline solution to replace traditional dual flowlines. However, the combination of a single flowline, downhill flow and high water cut presents several challenges for hydrate management after an unplanned shut down. Depressurization is the most commonly used technique to prevent hydrate blockages. But depressurization at high water cut may not be successful when the geometry of the flowline results in a liquid head in the flowline riser that is higher than the hydrate formation pressure at ambient conditions.
Options were examined for managing hydrates during high-water cut conditions using service lines in the umbilical to replace the functionality offered by a second flowline. The options examined included using the service line for dead oil displacement, continuous gas lift, expansion of trapped gas, mono ethylene glycol (MEG) injection after emergency shutdown (ESD) and bleeding subsea side trapped pressure. This paper will present an overview of each concept with respect to feasibility, cost, operability and risk issues.
The challenges associated with using the service line options were: ■Hydrate management during extended operations■Impact of the service line on subsea tree design■Support required from host facility■Operability and risk issues
The results of a tradeoff analysis were used to select one concept for detail engineering. The benefits of the single flowline system with the selected hydrate management strategy will be illustrated based on the analysis of a deepwater field development design case.
Comparison of Single- and Dual-Array Microseismic Mapping Techniques in the Barnett Shale
Authors: Warpinski N. R. , Kramm R. C , Heinze J. R. , Waltman C. K. 
Published: December 2007

Abstract
This paper shows a comparison of dual-array microseismic maps with single-well maps for horizontal wells in the Barnett shale. Results from two test cases showing gel and water fracturing maps are given and compared with initial production. Dual-array mapping provides for a much larger areal coverage and increased accuracy when accurate bottomhole locations and velocity structure are available, but do have trade-offs that need to be considered.
Interpreting the Depositional Facies of the Upper Gharif Fluvial System Using Oil-Based Mud Images: A Case Study in Central Oman
Authors: Amer A. , Alexander S. 
Published: December 2007

Abstract
During the early stages of developing Oman's A field, water-based mud (WBM) was used to drill all wells. With this mud system the wells suffered borehole stability problems, especially in the friable paleosols (fossil soils) of the Gharif formation. One of the advantages of drilling with WBM was the ability to run high-resolution microresistivity images.
In the second development stage of the field, oil-based mud (OBM) was used in order to reduce the severe borehole washouts. However, the benefits of microresistivity borehole images were lost.
With the development of the oil-based mud imager tool and its deployment in the A field, key geological and petrophysical information is provided for further successful field development.
This paper explains a new methodology for geologically evaluating the complex upper part of the Gharif formation by introducing integrated data from different sources. Using the electrical oil-based mud images integrated with acoustic images, core data and openhole logs, the facies distribution and typing of the Permian Gharif fluvial system are interpreted over the field.
Nine depositional facies were identified using the oil-based mud images: sand channel, heterolithic channel, abandoned channel, splay/chute, debris flow/sand flat, floodplain/swamp, tidal flat/intertidal, marine shales, and shallow marine limestone facies.
The Upper Gharif stratigraphic interval is subdivided into channel belts separated by thick floodplain shales. The paleocurrent analysis based on these subdivisions illustrates that, in the Upper Gharif, the large spectrum of trends observed for some layers is the result of deposition with almost no accommodation space (meandering channel), whereas other layers show clearer trends indicating possible deposition under higher energy (stream channel type). The value of the oil-based images has been its ability to delineate the channel belt trends and sand prediction for infill drilling.
The identification of these facies and their trends is critical for reservoir evaluation and in field development. However, recent infill drilling results in the Upper Gharif show that sand prediction remains the key challenge to successful development.
Design Considerations for Interventionless, Commingled Multizone Selective Sand Control Deepwater Completions
Authors: Burman J. W. , Renfro K. D. , Conrad M. , Parker C. , Turner D. , Franklin B. 
Published: December 2007

Abstract
Reducing operational risk and improving reliability are major drivers in deepwater completion design. Anadarko's Marco Polo Deepwater Project, located in Green Canyon Block 608 in the Gulf of Mexico, is a 4300-foot water depth development presenting unique completion demands. The Marco Polo Field was developed using multiple frac packs in 6 direct vertical access (DVA), dry tree wells from a TLP.
The completion intervals for Marco Polo are stacked pay zones (5 of the 6 wells have 3 perforated intervals) that were frac packed for sand control and productivity. The development plan is for most initially completed intervals to be commingled downhole, and provide future flow control options to maximize ultimate recovery from all zones. The initiation of production from all zones in each well was desired to be interventionless due to the inherent risk of slickline or coiled tubing operations. Finally, all tool hardware designs had to be compatible with frac packing operations.
This paper will detail the design criteria established for zonal isolation and fluid loss control for the project, testing protocols for the equipment, quality assurance in manufacturing and assembly, contingency plans for the operations and initial results.
Splines as an Optimization Tool in Petroleum Engineering
Authors: Archer R. , Zakeri G. , Vaudrey T. 
Published: December 2007

Abstract
Planning well placements and assisted history matching are examples of some of the difficult optimization problems that occur in petroleum engineering. In both problems objective function evaluations are computationally expensive because they involve forward simulations using reservoir simulators. When gradient based methods are applied to these problems derivatives of the objective function with respect to the parameters (i.e. well location or reservoir properties) are required. The simplest way to calculate these derivatives is by perturbation, which requires further expensive simulation runs. More mathematically complex methods can also be used but these can be difficult to implement.
Response surfaces are used to extract the most value from simulation runs that are made. Prior work has used kriging and least-squares methods to fit such surfaces. This work utilizes splines as a surface fitting tool. Splines are a useful tool because the derivatives required for a gradient based optimizer can be readily computed using various packages. Splines are shape preserving (i.e. convexity properties are unchanged). Constraints can be implemented when fitting splines.
This work demonstrates the application of the new spline based optimization procedure on a well placement problem. This example is based on a real 17 MMSTB oil field. The operators of the field planned to begin waterflooding. The optimization tool was used to plan the location (areally) of the water injection well. The well location determined using the tool is predicted to produce over 800 MSTB of incremental oil when compared to the original location proposed by the operators. The CPU requirements were modest, under 3% of the possible well locations were simulated. A history matching process is also demonstrated which is used to determine the ratio of vertical to horizontal permeability, a global porosity multiplier and the gas-oil contact depth.
Quantification of Depth Accuracy
Authors: Brooks A. , Wilson H. , Jamieson A. , McRobbie D. , Holehouse S. G. 
Published: December 2007

Abstract
Depth is a critical measurement in the economic development of a hydrocarbon asset. Almost all downhole activities, from making petrophysical measurements to setting packers, are performed remotely from surface. The common reference for all such activities is depth. A vertical depth error of less than one meter can have a financial impact counted in millions of dollars. However, despite the Industry's heavy reliance on depth, its accuracy is poorly specified.
This paper describes a set of error terms which allows proper quantification of along-hole depth uncertainty for commonly used measurement systems. Additionally, the terms include correlation coefficients that allow quantification of the relative uncertainty between two competing measurements.
Although the physical measurement that is made at the rig site is normally along-hole depth, it is vertical depth that defines the relationship between sub-surface features. The quantification of along-hole measured depth uncertainty is therefore only a partial solution; it is also necessary to estimate vertical uncertainty.
The directional survey of the wellbore defines vertical depth for any along-hole depth, and directional surveys are routinely accompanied by an estimate of positional uncertainty. A method is described for combining the directional survey's estimate of the wellpath's vertical position uncertainty with the along-hole depth uncertainty associated with another downhole operation, resulting in a valid vertical uncertainty for that operation.
Adoption of the techniques described in this paper will result in valid estimates of depth uncertainty, which it is hoped will encourage better depth management practices, and result in more productive wells.