bluuebunny/crossref_metadata_2025_split huggingface dataset:
Opukushi Horizontal Well Campaign: Completion Design and Wellbore Clean-Up
Authors: Osode P. I. , Dijkema R. W. 
Published: December 2007

Abstract
As part of on-going initiatives to improve the Opukushi field ultimate recovery and production potential, horizontal well technology was introduced during the second phase of the field development, which started in 1995. Following the review of three previous wells, including the first Shell-Nigeria horizontal well, which was completed in 1992, some modifications of the completion design were recommended. While still on the learning curve of drilling horizontal wells, another 3-well horizontal drilling campaign was successfully executed in the Opukushi field in 1996.
Openhole liner completion design was selected because of the unconsolidated sandstone formation which characterizes the shallow horizons of the field, with the wells targeting undeveloped reserves located at a depth of ~7500 ft tv-ss. All the wells were completed in thin oil rim sands of ca. 70 ft, with 5-1/2" × 4-1/2" tapered slotted liner (SL) assemblies installed across 2300–3300 ft of 8-1/2" drainhole sections. The horizontal sections were drilled with a low-solids drill-in fluid while wellbore clean-up was effected with a coil-tubing unit utilizing a nitrified acid at underbalance condition.
This paper presents a review of the 3-well completion design and installation technique, as well as the horizontal wellbore clean-up procedure adopted. The wells’ performance evaluation, based on test data and Production Logging Tool (PLT) results, has also been presented to show a comparison with the conventional well performance. The recorded high productivity improvement factor (PIF) of above 10 has demonstrated the superiority of horizontal well applications.
Optimizing Fracture and Completion Designs in the Westerose Field
Authors: Aunger D. , Dunn-Norman S. , Kenny J. , Halvaci M. , Griffiths E. , Barnhart W. 
Published: December 2007

Abstract
The Westerose Gas Field produces gas from the Glauconitic Formation. This formation can be subdivided into an upper permeable sand (1–10 mD) and a lower sand (normally less than 0.5 mD). The reservoir quality of the lower sand is fairly uniform throughout the area, but the upper section can contain either permeable "bar" sands or low permeability "interbar" sands. "Bar" type sands have greater thickness than the "interbar" sands and, in general, contain greater gas reserves. Nevertheless, inter-bar sands are estimated to contain up to 225.4 MMm3 (8 Bcf) original gas in place per section, which is a significant gas target. These reserves have not been extensively developed since vertical wells that penetrate the interbar sand are usually very poor producers.
An experimental pilot project was conducted to determine the feasibility of developing additional gas reserves in the tight sands located between the main bar trends. As part of this work, a study was conducted to analyze and compare fracturing and completion alternatives in the Glauconitic "bar" and "interbar" sands. For each type of sand, optimal fracture designs for vertical wells were determined and vertical fractured well performance was compared to stimulated and unstimulated horizontal wells drilled either parallel or perpendicular to the minimum in-situ stress. This paper reports the findings of the Westerose fracturing and completions study, and field results from wells drilled and completed in 1997 in accordance with the study recommendations.
Gulf Of Alaska Wave Climate Program
Authors: McLeod Wilfred R. 
Published: December 2007

American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc.
Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussion may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines.

Abstract
This paper deals with a new deep water wave data acquisition program. The author believes that program. The author believes that the uniqueness of design, as well as planning, that went into this program will be invaluable to others program will be invaluable to others contemplating wave climate studies in other coastal locations. Detailed information on equipment selection and method of data analysis is provided. The potentially strong provided. The potentially strong currents, up to 5 knots, that will be encountered in the study area, and the limited buoyancy of the standard (0.7-M) Waverider, pose a difficult mooring problem. The use of Waveriders of larger diameter (0.9-M) along with the mooring system to be used in this study are discussed.
Wave spectra measurements made during severe and normal conditions will help to compensate existing severe and normal hindcasts. The data will also be especially useful for testing new operational forecasting schemes, in an analytic sense, as the complete records become available.

Introduction
The wind and resulting wave climate is a principal concern to those responsible for offshore operations of the petroleum industry. This is particularly true for heavy weather areas such as the Gulf of Alaska, where the design of safe and yet economical offshore structures depends on accurate design wave criteria. A data base which includes actual wave measurements is important to the development of reliable statistics. Thus, knowledge of both normal and storm wave conditions is essential to the formulation of logistic, operating, and construction plans.
Interpretation of Horizontal Well Performance in Complicated Systems by the Boundary Element Method
Authors: Jongkittinarukorn Kittiphong , Tiab Djebbar , Escobar Freddy H. 
Published: December 2007

Abstract
This paper presents the solutions obtained by using the boundary element method to simulate pressure behavior of horizontal wells in complicated reservoir-wellbore configurations. Three different types of wellbore and reservoir models studied by Jongkittinarukorn (1998) are reported in this study. They consist of a snake-shape horizontal wellbore intersecting a two-layer reservoir with cross-flow, a horizontal or inclined well in a three layer reservoir with cross flow and a vertical well intersecting a two-layer reservoir without cross flow. Special attention was paid to the influence of the wellbore inclination angle, the distance from the wellbore to the different boundaries and the permeability ratio.
The Application of New Centralizer Types to Improve Zone Isolation in Horizontal Wells
Authors: Kinzel Holger , Martens James G. 
Published: December 2007

Abstract
Horizontal Drilling has become a commonly used technology to increase the productivity index of single wells and to increase the recovery factor of entire fields. A rising number of horizontal liners are cemented and perforated to be able to solve production problems, such as water and gas coning.
Cementation of a horizontal liner requires extensive planning and engineering. One of the important issues for mud removal is good string centralization. New types of centralizers designed specifically for the application in horizontal well applications have successfully been used in horizontal wells worldwide. Selection criteria for both types of centralizers, bow-type and rigid, and a comparison of their main parameters based on mathematical modeling, are described.
Analysis and Modeling of Fractured Reservoirs
Authors: van Dijk Janpieter 
Published: December 2007

Abstract
The analysis and modeling of fracture and fault patterns on various scales has obtained a major role in hydrocarbon exploration and development. Mainefforts regard the optimization of well bore orientations with respect to fracture network characteristics, the identification of well site locations inorder to enhance productivity, and the improvement of the estimates ofgeometrical parameters such as matrix block sizes and shapes (sigma factor), representative elementary volumes (REV), and fracture porosity distribution forreservoir evaluation.
A number of case studies will be presented regarding exploration and production activities in various types of naturally fractured reservoirs with poor primary matrix permeability. The new techniques developed relate to theissues of predicting parameters such as location, density, interrelation and orientation of fracture sets in complex tectono-stratigraphic settings.
The optimum location and deviation of an exploration well to be drilled canbe established by applying Fracture Potential and Domain Mapping technologieson elaboration's of high quality 3D seismic datasets (amplitude, geometry, coherency), calibrated with available (oriented) core and log datasets(conventional logs, borehole viewers, borehole shape analysis, etc.). Theoutcome of these methodologies are a series of maps which predict fracturedensity and orientation throughout prospects and reservoirs, which can be used to choose optimum locations for exploration and development wells for which fracture and fault orientations can be predicted. Furthermore, strike domaininterference can help in the detection of fluid flow paths and can give clues to the interpretation of well behavior. Combinations of deterministic and probabilistic three-dimensional modeling of the subseismic fracture zone network provides a sophisticated tool to investigate the tectonic texture of the rocks to be drilled, for which fracture orientation can successfully bepredicted.
The remarkable accuracy with which the texture of the fracture network can be analyzed, modeled and predicted applying a range of new technologies is highly encouraging and opens a whole new perspective for challenging future objectives related to the exploration and development of naturally fractured reservoirs.
P. 31
Effects of Rock Heterogeneities on Capillary Pressure and Relative Permeabilities
Authors: Mannseth T. , Mykkeltveit J. , Nordtvedt J.E. , Sylte A. 
Published: December 2007

Abstract
The absolute permeability of a core plug may be heterogeneous and anisotropic, e.g., due to small-scale laminae or cross bedding. Standard methods for determination of the two-phase flow functions, capillary pressure and relative permeabilities, assume a homogeneous and isotropic core. In the implicit method, where a simulator is used to history match the measured data, heterogeneity and anisotropy can be accounted for.
In this paper, the importance of accurate modeling of heterogeneities for the determination of the two-phase flow functions is addressed. Several l-D and 2-D permeability distributions with realistic permeability contrasts are utilized to investigate into the effects of rock heterogeneities on the inferred flow functions.
P. 67
Successful Shale Drilling Using a New Environmentally Compatible Potassium Carbonate/Polymer/PolyGlycol Mud System: Design and Field Experiences
Authors: Mascarà S. , Vallorani F. , Jachnik R. , Formisani D. 
Published: December 2007

Abstract
This paper presents laboratory data and field application results on a new water based mud system which utilizes Potassium Carbonate, a special polymer formulation and a polyglycol. The surfactant properties of the polyglycol around it's cloud point, the existence of normal force and extensional viscosity in the mud prepared under low shear, and the successful application of the mud system in southern Italy to drill massive shale sections with high kaolinite clay content are all discussed.
Unique ESP Completion and Perforation Methodology Maximises Production in World Record Step-out Well
Authors: Blosser W. , Davies J.E. , Newberry P. , Hardman K. 
Published: December 2007

Abstract
This paper describes the key planning and operational experiences gained during the perforation and completion phase of the world record step-out extended reach well at the Wytch Farm oilfield in Dorset, England. The paper presents an overview of how the M- 11 well was successfully completed and describes how a combination of existing technology and new technology has been applied to achieve Wytch Farm's most prolific producer to date.
Well 1M-11SPy (M-11) holds the world record for the highest horizontal departure, 10114m, at any vertical depth, and a record departure: to true vertical depth (TVD) ratio of 6.24. The Wytch Farm extended reach wells are completed with cemented, perforated liners and electrical submersible pumps (ESPs).
A new technique for perforating the well was developed to maximise inflow efficiency. This technique enables underbalance perforating without any subsequent requirement for a well kill. The impact of these improvements on completion efficiency is discussed, along with the associated operational issues.
The large departure required the ESP to be set at 8625m, another world record, with the 1000 HP motor requiring a new 7kV cable system and a 1500 kVA variable speed controller (VSC) at surface. This paper describes the background of VSC selection and the physical testing of the complete ESP/cable/VSC system that was conducted prior to installation to ensure that sufficient torque could be generated at the ESP for a range of start-up and operating conditions, and to configure the new type of VSC used for optimal system performance.
The paper reports experience gained, and reviews lessons learned.
P. 579
Intelligent Completion Systems --The Reservoir Rationale
Authors: Jalali Y. , Bussear T. , Sharma S. 
Published: December 2007

Abstract
Two reservoir displacement scenarios are analyzed, wherein control of downhole flow conditions has a marked effect on production performance. The first relates to depletion of a two-layer gas reservoir disposed toward development of crossflow, and the second relates to control of the injectivity profile in a rate-sensitive waterflood. For each scenario a conceptual control architecture is proposed, and the impact of this architecture on production performance is assessed.
Production-Induced Compaction of Sandstone Reservoirs: The Strong Influence of Field Stress
Authors: Hettema M.H.H. , Schutjens P.M.T.M. , Verboom B.J.M. , Gussinklo H.J. 
Published: December 2007

Abstract
During the production of sandstone reservoirs, changes in the pore pressure causes changes in the stresses acting on the reservoir. Reservoir compaction is usually determined by assuming uniaxial strain conditions, i.e. no lateral strain during depletion. Field data of the Groningen gas field indicate that the stress development of the field deviates significantly from the stress path defined by uniaxial strain conditions. Laboratory experiments performed on Groningen core samples show that the applied stress path has a strong influence on the depletion-induced compaction behaviour. We discuss the consequences of these results for the field compaction behaviour by considering the responsible mechanisms. Our findings bring the laboratory derived compaction in line with the in-situ measured field compaction.
P. 547
4D Seismic Interpretive Processing: Optimizing Differential Imaging For Reservoir Monitoring
Authors: Burns C. Scott 
Published: December 2007

Abstract
Data from four repeated 3D seismic surveys over the Oseberg Field will be used to demonstrate the concept of 4D interpretive processing: To optimize 4D processing parameters & methodology and to gauge their cost effectiveness & sensitivity to mapping changes in reservoir properties, it is critical to incorporate analysis of reservoir dynamics & rock physics. Comparative analysis begins by building a reference of the seismic response-seismic attribute maps & 4D model-based classification-related to estimated changes in reservoir properties due to production. Subsequent cross-equalization, position error analysis, and optimization of amplitude transforms can then be efficiently performed with the objective of improving reservoir differential imagery.
Results from the 4D seismic analysis on the Oseberg data indicate that there is general agreement between differential seismic images and reservoir simulation estimates of volume displacement of oil by gas.
P. 329
Screening Criteria For Evaluating the Development Potential of Remaining Oil in Mature Fields
Authors: Weber K.J. , Dronkert H. 
Published: December 2007

Abstract
Continuing reservoir management at mature stages often concentrates on delineating pockets of remaining mobile oil. This is becoming a major task for reservoir geologists and petrophysicists. Many old fields are coming up as investment targets for reactivation and there is general consensus that modem techniques can lead to additional recovery of between 10 and 20 percent. However, there are many pitfalls which can render an apparently attractive project into an economic failure. This paper will discuss the non-technical screening criteria related to reservoir architecture, accumulation condition and production history.
Mobile remaining oil can be found in a number of predictable locations in reservoirs depending on their structural style and facies.
Attic oil along faults is perhaps the most simple configuration but sizeable volumes of remaining oil can also occur as a function of reservoir stratification and lateral discontinuity. A systematic overview of the different types has been compiled based on structural or stratigraphic lateral continuity and vertical reservoir connectivity. This leads to four main types with some sub-groups for each of which screening criteria have been derived on the basis of field examples and models. The screening criteria specify minimum conditions which may lead to economic re-development with horizontal side-tracks from existing wells. In addition recommendations are given with respect to data gathering to confirni the presence of economically viable targets.
P. 345
Drag Reducer Performance Measurement-A Scaled-Up Laboratory Test Compared With a Field Trial
Authors: Hamouda A. A. , Strand S. , Johnson A. , Tebboth L. 
Published: December 2007

Abstract
Drag Reducing Agent (DRA) is used in numerous single-phase pipeline systems to reduce operating pressures, increase capacity, and decrease reliance on pumping. For a given pipeline system, prediction of the DRA performance is unreliable. Therefore, a reliable laboratory flow-loop test, the results of which could be scaled-up to the full-scale pipeline, would be valuable.
During transportation, the oil temperature decreases, the rate of decrease depending on factors such as flow rate, insulation, and surrounding medium. It has been shown in our previous laboratory studies that DRA performance, normalized by a function of Re. (f) 0.5, in a non-isothermal system can be 20% below that of an isothermal system. This behavior has shown to be dependent on the characteristics of the oil (e.g. wax appearance temperature, wax content, oil composition etc.).
The above laboratory observations have lead to a method for scaling-up flow-loop test results to enable prediction of the full-scale field data. The subject of this paper is the validation of these scale-up methods. For this validation, flow-loop tests were performed on the crude oil from a well instrument singlephase export pipeline. The loop test results were scaled-up without knowledge of the DRA performance in the actual pipeline. In the loop tests and field trial a range of DRA concentrations were tested for DRA performance, effect of DRA on wax deposition, and the effect of wax crystallization on DRA. The phenomenon of the effect of the DRA on the wax deposition profile, as shown in our previous studies, was confirmed in this test. The scaled-up loop test results agreed with the field measurements to within ±5% for the tested DRA concentration and ± 13% for the extrapolated concentrations.
Influence of Oilfield Chemicals on the Surface Tension of Stimulating Fluids
Authors: Dabbousi B. O. , Nasr-El-Din H. A. , Al-Muhaish A. S. 
Published: December 2007

Abstract
Surface tension plays a very important role in the stimulation of gas wells. A low surface tension is required to reduce capillary forces that trap the aqueous phase in the formation. Accumulation of the aqueous phase near the wellbore area, known as water blockage, leads to a significant reduction in gas production.
An experimental study was conducted to examine the effects of various acids and stimulation additives on surface tension. A Krüss tensiometer (Model K-12) was used to conduct surface tension measurements. Acids examined included: HCl, acetic, citric, formic, and combinations of these acids. Stimulation additives tested included: mutual solvent, short-chain alcohols, corrosion inhibitors, hydrogen sulfide scavengers, iron-control agents, and clay stabilizers. In addition, the effects of three classes of surfactants (nonionic, cationic and anionic) on surface tension of acid solutions were investigated.
The surface tension of acid stimulating fluids is a complex function of acid type, concentration, and additive type and concentration. Acetic and formic acids had lower surface tension values than HCl, especially at high acid concentrations. The surface tension of the organic acids examined depended on the pKa value of the acid. Organic acids with high pKa values had low surface tension values. The surface tension of hydrochloric acid can be reduced by mixing with acetic acid. EGMBE lowered the surface tension of acetic, formic and hydrochloric acids up to 10 wt%. Increasing the concentration of EGMBE above 10 wt% had no significant effect on the surface tension of these acids. The effect of organic acid strength on surface tension diminished in the presence of EGMBE. Short-chain alcohols reduced the surface tension of 15 wt% HCl with the greatest reduction obtained with n-butanol. Citric and erythorbic acids, which are usually used as iron control agents significantly reduced the surface tension of 15 wt% HCl. Ionic surfactants reduced the surface tension of hydrochloric acid more than the two nonionic surfactants tested. The three corrosion inhibitors examined reduced surface tension up to a critical concentration beyond which they had no effect on surface tension. An aldehyde-based H2S scavenger lowered the surface tension of 15 wt% acid solutions at very low concentrations. Clay stabilizers (cationic polymers) did not significantly affect the surface tension of 15 wt% HCl. Addition of a hydrogen sulfide scavenger, a nonionic surfactant or a corrosion inhibitor into solutions of 15 wt% HCl and EGMBE had a small effect on the surface tension of the acid.