bluuebunny/crossref_metadata_2025_split huggingface dataset:
Installation of Advanced Completions in the Oseberg 30/9-B-38 B Well
Authors: Rundgren G. , Hydro Norsk , Algeroy J. , Hestenes L. E. , Jokela T. , Raw I. 
Published: December 2007

Abstract
This paper describes an innovative completion solution that allows commingled oil production from a well with three individual sections. The well is operated by Norsk Hydro in the Oseberg field. Included in the description are equipment selection, design and development details, installation procedures, and "lessons learned" after installation of the fully hydraulic tubing-retrievable advanced completion system. This completion provides isolation and surface production control of the three sections in Well 30/9-B-38 B, and allows viable and economical production from each.
The three fluvial sand channels were isolated using a new packer that allows bypass of individual conduits, electric or hydraulic, necessary to monitor and operate the flow control valves.
A tubing-retrievable hydraulic flow control valve was developed for this project to provide remotely controlled adjustment of flow from the reservoir. The valve uses one dedicated 0.25-in. control line to the surface to hydraulically control the choke section of the tool. An indexer adjusts and secures the choke in one of 10 positions.
The completion was successfully installed in May 2000, and the well became the highest producer in the field. Because of unacceptably high gas production, flow from the upper valve was adjusted to reduce flow from this section. This adjustment effectively reduced gas production and enhanced oil production from the lower sections. Without control of flow from individual sections, production would have been choked back at the surface because of limited gas-handling capacity. Choking at the surface would have negatively affected the overall well production.
A Simple Acoustic Wave Propagation Model for Interventionless Well Completions
Authors: Shah Vimal V. , Skinner Neal G. 
Published: December 2007

Abstract
The use of interventionless completion equipment is increasing in the industry. To support this trend, a system that can remotely control completion equipment by transmitting a series of precisely timed acoustic pulses has been developed. The pulses are delivered at the surface using compressed air or nitrogen and are transmitted through the tubing to the downhole equipment.
Although this process may sound simple, in reality, propagation, reflection, and attenuation of acoustic waves in tubing is rather complex. The confined fluid in the tubing forms a variable telemetry channel. This channel depends on the nature of the fluids present, the air column above the fluids, and the properties and geometry of all tubulars in the well as well as the physical construction of the completion equipment.
A numerical model has been developed to characterize the nature of the transmission channel, identify arrival times of acoustic signals, and predict signal attenuation and the decay time for multiple reflections. The success of this model has greatly increased the viability of the interventionless completion system. Signaling times and surface pulse amplitudes can be adjusted based on information provided by the model.
This paper will provide details of the numerical model and discuss the use of the model for interventionless completion as well as other applications of the model.
Completion Design and Implementation in Challenging, Extreme HP/HT Wells in California
Authors: Hahn D. E. , Burke L. H. , Mackenzie S. F. , Archibald K. H. 
Published: December 2007

Abstract
As producing companies search for significant hydrocarbon resources, it has become necessary to pursue opportunities in frontier geologic horizons and geographic locations. This pursuit frequently results in encountering High Pressure – High Temperature (HP/HT) environments. The petroleum industry defines HP/HT wells as those exceeding 10,000 psi and 300°F.
Several companies have drilled into HP/HT horizons in the California San Joaquin basin over the past 30 years, but generally operations were halted due to equipment limitations or due to limited hydrocarbon indications. In late 1998, a significant gas flow was identified from the Temblor formation at depths below 17,100 ft, with geologic information indicating a potential Temblor sand gross thickness of up to 3600 ft.. The pressure design basis for subsequent wells assumed an estimated equivalent pore pressure of 16.9 ppg. This information and other producing conditions, indicated potential bottomhole conditions of 425° F and 18,000 psi. Produced fluids also indicated the presence of hydrogen sulphide (H2S), which, at these pressures, dictate sour service metallurgical specifications.
These potential extreme well conditions required very detailed completion engineering design, equipment qualification, rigorous planning, and precise field execution to achieve successful well completions. This paper will detail and discuss the well completion design basis and issues; equipment/perforating limitations and qualification tests, tubular stress and loading analyses, high-density completion brine usage, and actual field operational experiences.
Numerous contingencies were planned in detail, some of which had to be implemented. The most significant contingency operation was a high pressure coiled tubing milling operation to clean out 2500 ft of formation and perforating debris, which plugged the tubing string.
Case Studies Using Advanced Interpretation Techniques for Induction Logs
Authors: Barber Thomas D. , Shray Frank 
Published: December 2007

Abstract
Because of their considerable range of investigation, induction-logging instruments are susceptible to a variety of environmental effects. The problems arising from high relative dip or high shoulder-bed contrasts have proven difficult to solve. The industry trend of using oil-based muds to drill these formations has prevented the use of the preferred solution—a laterolog device— in such cases. For multiarray induction tools, the problems resulting from high-conductivity contrast have recently been solved in real-time processing. Maximum-entropy inversion of the induction data is another recently proposed solution for both problems.
These two methods are now readily available to extract formation resistivity in the presence of troublesome environmental effects. The methods have been developed to meet formation evaluation needs given the reality of current drilling practice of using nonconductive muds to drill high-resistivity formations with high-conductivity shoulder beds.
This paper examines several cases of multiarray induction data ranging from near-vertical wells to high-angle wells. Several cases with high shoulder-bed contrast, from low- to high-relative-dip angles, illustrate formation resistivity measurements free from these environmental effects. The maximum-entropy method provided resistivity solutions in the presence of the single or combined effects of high relative dip and high shoulder-bed contrast. This method, however, is too slow to be suitable for real-time processing. In the vertical well cases, the maximum-entropy method and the real-time method and provide similar results in the presence of high shoulder-bed contrast. Modeling methods validated the outputs from both the real-time and the maximum-entropy processing methods.
Field Test Results Demonstrating Improved Real-Time Data Quality in an Advanced LWD Acoustic System
Authors: Leggett James V. , Dubinsky Vladimir , Patterson Doug , Bolshakov Alexei 
Published: December 2007

Abstract
Acoustic compressional slowness measurements are critical for geomechanics, petrophysical and seismic applications. Conventional acoustic wireline data is often unavailable due to cost constraints or well problems, thus increasing the need for acoustic Logging While Drilling (LWD). The LWD environment creates additional demands on borehole acoustic measurements as compared to wireline, due to tool strength requirements and drilling noise. These issues have consistently limited the LWD acoustic tool's ability to provide wireline equivalent data quality. The conventional LWD methods have incorporated single direction or single axis acoustic systems with short transmitter-receiver (TR) spacing (typically 4 ft). Technical features of a new acoustic LWD tool incorporating long TR spacing (+10 ft) with an array containing six four-element receiver stations to obtain omni-directional measurements will be discussed. Field test data examples will show the improved quality of this real-time measurement.
The tool configuration was optimized as a result of comprehensive modeling and lab testing of key system components. Greater source power combined with multi-frequency adjustable signature capability allowed the TR spacing increase. The system quality was enhanced due to improved software and hardware functionality. An improved receiver array configuration allows for better noise isolation and response to formation arrivals. In addition, real-time downhole monitoring of the drilling noise coupled directly into the collar allows for further data quality enhancement. Redundancy and a modular design approach were key for providing a robust and reliable system with fast tool setup and data downloading.
The field test examples will present data acquired in different drilling modes to demonstrate the improved signal-to-noise ratio for raw and stacked data in both fast and slow formations. As compared to industry standards, faster Rate of Penetration (ROP) is achievable due to enhanced downhole processing capabilities. The real time slowness results compared to conventional wireline shows the systems' ability to make comparable measurements. These field test results demonstrate an improved data quality with this new LWD acoustic system.
Enhanced C/O Logging as an Effective Cased Hole Saturation Monitoring Solution Case Histories from the Gulf of Suez
Authors: Elshahawi H. , Gad K. , William A. , Mostafa Azzam 
Published: December 2007

Abstract
As oil fields mature, progressively more effort must be devoted to diagnosing production and reservoir problems and to finding cost-effective solutions for those problems. One of the key inputs to any reservoir management scheme is the timely monitoring of behind-pipe fluid saturation profiles across the field. Using the C/O ratio to compute water saturation offers many advantages over conventional techniques that depend on formation water salinity. The C/O ratio relates directly to the volumes of oil and water in the formation, and conversion of C/O ratio to oil saturation is based on a very large database acquired using laboratory formations with a wide range of wellbore environments. Recent enhancements in spectral processing techniques for pulsed neutron spectroscopy tools have improved accuracy and precision of measured carbon-oxygen (C/O) ratios. These include improved elemental standards and the development of a full spectrum calibration to provide better accuracy and precision in a wider range of porosities and in the presence of gas.
Many of the Gulf of Suez fields are characterized by edge water drive mechanisms or are undergoing water flooding with different salinity water than the formation water. These conditions have traditionally presented formidable challenges to cased hole saturation monitoring, often resulting in highly uncertain results. This paper highlights several case histories from the Gulf of Suez which demonstrate how Enhanced C/O methods were used to effectively detect unswept hydrocarbons and track gas/oil/water contact movements in the reservoirs.
Riserless Drilling Technique Saves Time and Money by Reducing Logistics and Maximizing Borehole Stability
Authors: Johnson Michael , Rowden Michael 
Published: December 2007

Abstract
This paper describes "Riserless Drilling" methodology and the new processes being employed to redefine interval limitations in deepwater operations. This discussion includes limitations of conventional methods, types of riserless fluids in use today as well as future considerations, the benefit of new hardware designed to optimize the process, challenges accompanying this new technique and a review of several case histories using this same riserless drilling technique.
The Foinaven Field
Authors: Newcombe Gunther , Young Stuart 
Published: December 2007

Abstract
The Foinaven field was the first deepwater development West of the Shetlands in the Atlantic Ocean. BP and its partners took a major financial and technical risk in developing the field but wanted to ensure that any environmental and safety concerns were fully addressed. The field has been on production since November 1997 and has produced over one third of the 250mmbbls reserves, achieving a production record of 130,000 bopd in August 2000. The operational track record to date has been world class and has been achieved through a combination of integrated field management and innovative problem solving. During 2001 and 2002 over £200 million will be invested in developing new reserves and work is in progress to mature additional projects. The emphasis of this paper will be on operational experience and lessons learnt and also to highlight future opportunities and the technologies needed to deliver them.
Near-Wellbore Modeling to Assist Operation of an Intelligent Multilateral Well in the Sherwood Formation
Authors: Lucas C. , Duffy P. , Randall E. , Jalali Y. 
Published: December 2007

Abstract
We examine the two-year history of an extended reach dual-lateral well, in which lateral production has been controlled by downhole flow control valves to minimize water production and optimize the lift effected by a high-horsepower electrical submersible pump. We assess the impact of downhole flow control on production performance by a modeling exercise consisting of refining a region surrounding the wellbore to reproduce the observed production history, and then forecasting the performance of that refined model under alternate completion scenarios. This methodology can also be used to select valve settings that are most advantageous to production.
Fife Field UK - Rejuvenation of a Mature Asset
Authors: Bush K. R. , Wakefield J. , Shepherd M. , Beattie K. 
Published: December 2007

Abstract
The Fife Field situated in blocks 31/26a, 39/1, 31/27 and 39/2a (Figure 1) came on production in August 1995, with an expected field life of 4 years and reserves of 34 million barrels. The initial oil production rates from the field were prolific and in line with the field development plan, however, water production commenced soon after start-up and increased continuously in the early development wells. The impact of the water cut-development on the project economics and ultimate recovery was severely negative and as a result, an intensive sub-subsurface work programme was initiated to recover the situation.
This effort has been sustained and the field has now produced over 39 million barrels of oil. It is currently producing at 17,500 bopd. Production rates have been maintained due to the subsurface work programme, which has lead to the identification and drilling of new locations within the field. The work programme and latest wells to be drilled are described in this paper
Application of Two Methods to Evaluate Matrix Acidizing Using Real-Time Skin Effect in Saudi Arabia
Authors: Al-Dhafeeri A. M. , Engler T. W. , Nasr-El-Din H. A. 
Published: December 2007

Abstract
The effectiveness of acid treatment is commonly evaluated by a reduction in skin factor determined through pre-and/or post- well test analysis. However, mathematical models have been developed to monitor the change in skin while injecting acid and therefore obtaining real time skin values. This work demonstrates the application of monitoring real change in skin effect during the acid treatment with several field examples in carbonate formation.
Two real-time monitoring methods1,2 were used to capture the effect of treating fluids on the formation. The field applications using the two methods were conducted on two water injectors in Saudi Arabia to evaluate stimulation performance with in-situ Gelled Acid systems. From the calculated bottomhole pressure and injection rate, skin effect was determined as a function of time. In this manner, the effectiveness of acid injection into the formation was estimated.
The Paccaloni's method, which is a direct result of the steady state assumption, was conducted to monitor the skin factor during the acid job. The second method, by Prouvost and Economides was also used to illustrate the effect of the treating fluid on formation damage, but is based on transient flow equations. Both methods can readily be included in acid treatment monitoring; however, the latter method is preferred due to the better agreement in the field cases.
This study provides a field application comparing the two methods and demonstrates the ability to capture the effect of diversion when the gelled acid increased viscosity in the formation by a subsequent increase in skin, and also the cleanup (decrease skin) that occurred when the regular acid reacts with the formation. This study also helps field engineers to ensure that no damage remains and no excessive acid is injected. The benefits of applying these two methods result not only in an operation cost reduction but also in a higher return on the stimulation investments.
Improved Techniques of Deepwater SBM Displacements: A Case History
Authors: Messler D. , Kippie D. , Webb T. 
Published: December 2007

Abstract
Wellbore cleanups are an integral part of the effort to reduce formation damage during completion operations. One operation that can significantly impact the cost of the well completion is the displacement from mud to completion brine. SBM (synthetic-based mud) cleanups pose unique challenges due to the emulsifying tendency of the additives to the synthetic base fluid. In deepwater, there are at least two displacements that compound an already difficult task, i.e., the riser and the casing. This paper demonstrates how a combination of software design tools, laboratory optimization and characterization, and post job evaluation led to improved displacement practices for the deepwater wells evaluated for this paper.
Lessons Learned from a Hundred Frac Packs in the Campos Basin
Authors: Neumann L. F. , Pedroso C. A. , Moreira L. , Bezerra de Melo R. C. 
Published: December 2007

Abstract
This paper presents the state of the art in frac packing learned from more than a hundred operations performed in the Campos Basin, offshore Brazil.
Many reservoirs in the Campos Basin are clean tertiary age sandstones, very unconsolidated, with high to ultrahigh permeability. In this scenario, in order to get low skin completions, high conductivity fractures must be created. These can only be obtained with the use of aggressive tip screen out (TSO) techniques. For these reasons, no questions remain about the superiority of frac pack when compared with conventional gravel pack.
Since February 1996, when the first frac pack job was performed, many challenges have been overcome, especially those related to handling leak off in very high permeability and the correct use of rock mechanics properties for proper frac pack design. These include minifrac analysis for very low efficiency fracturing fluids, the use or not of spurt loss, how fracturing fluid efficiency is affected by prior calibration tests, horizontal stress anisotropy for unconsolidated sands, stress contrast for layered sandstone's, etc.
Others lessons have been learned such as: the need for high quality fluid, high quality proppant, good proppant placement, as well as calibration tests, real time design and BHTP data collection for all jobs (from electronic gauges or from live annulus).
High Temperature Acidization to Prevent Fines Migration
Authors: Huang T. , McElfresh P. M. , Gabrysch A. 
Published: December 2007

Abstract
As reservoirs deplete and water production increases, fines production often ensues. The produced fines then cause various forms of damage including screen plugging. To alleviate the plugging, acid washes are pumped onto the screens and then brought back to surface. Often this treatment is only a temporary solution and re-treatment is required. This paper demonstrates a more permanent solution to fines plugging through acidization of the surrounding formation and removal of the source of the fines. In high temperature wells the choice of acid must be done so that the formation is not damaged but the fines are removed. A series of tests done on clay-rich cores shows that a new organic acid in conjunction with hydrofluoric acid can successfully remove fines and stimulate production. Conventional organic acids will damage the screens at high temperatures through corrosion. This new acid has very low corrosion at high temperatures. Corrosion tests show that at 350 °F the corrosion rate caused by this organic acid is 0.001 lbs/ft2 on 22Cr for 16 hours. Core flood testing demonstrates that these organic acid:HF mixtures can effectively remove fines at temperatures up to 400 °F.
Chemical Fluid-Loss-Control Systems for Severe Environments: Taking Conventional Systems to a Higher Level
Authors: Kippie David P. , Horton Robert L. , Foxenberg William E. , Arvie Morris 
Published: December 2007

Abstract
Controlling fluid losses to the formation, both before and after completions, is critical to optimizing production. Fluid-loss control can be achieved through the use of either mechanical or chemical means. Chemical methods control losses to the formation by increasing the base fluid viscosity with linear or crosslinked polymers or by forming a low-permeability filter cake on the formation face. However, performance limitations have prevented the use of such traditional ‘pills’ in high-stress environments, i. e., those that include high temperature, high density, low pH, high differential pressure, and high concentrations of divalent cations, Zn2+ and Ca2+. These limitations result in accepting excessive losses or employing less-than-ideal methods.
This paper describes fluid-loss pills developed for high-stress applications for both solids-free and solids-laden systems. Among the new developments are linear gel-based fluids stable at high temperature for extended periods. For example, we present data on HEC-based fluids stable at temperatures as high as 300°F and in densities in excess of 16.5 lbm/gal. Solids-laden pills are presented that have been field tested under severe conditions including high-density zinc brines up to 18.7 lbm/gal and temperatures up to 325°F. Laboratory data are provided that demonstrate effective fluid-loss control for at least 5 days under these extreme conditions. Formation damage and filtercake cleanup results are included. Several solids-free and solids-laden systems are documented through both lab and field case histories.