bluuebunny/crossref_metadata_2025_split huggingface dataset:
Addressing the Clay/Heavy Oil Interaction When Interpreting Low Field Nuclear Magnetic Resonance Logs
Authors: Manalo F. P. , Bryan J. L. , Kantzas A. 
Published: December 2007

Abstract
Low field nuclear magnetic resonance (NMR) in the form of logging tools, bench top analysers or on-line sensors has shown tremendous promise for the interpretation of logs and subsequent characterization of heavy oil and bitumen reser-voirs as well as the evaluation of recovery efficiency. The key for this success is the ability to identify properly the NMR response of the heavy oil and bitumen components of the spectra. Contrary to earlier belief on this topic, NMR can de-tect at least part of the response of heavy oil and bitumen ei-ther down-hole or in the production line. The majority of the spectra for heavy oil and bitumen samples are detected at re-laxation times less than 10 ms. In clay free sands this spec- trum is quite clear and the response of the NMR interpretation algorithms is accurate. However, the spectra of sand contain-ing clays show clay bound water to be in the same range as bitumen. Not properly accounting for the contribution of the clay bound water in NMR spectra results in the overestimation of oil or bitumen content of a given formation. This paper presents experimental results of heavy oil samples and also the spectra of clay bound water for common clays found in Al- berta and Saskatchewan. After the spectra are compared inde-pendently, sand packs containing different amounts of clay and bitumen are prepared and their NMR spectra are obtained. Patterns of spectra overlapping are identified and a prelimi-nary clay bound water prediction algorithm is presented. This algorithm allows for the separation of the oil contribution from the total NMR spectrum. Examples from different formations illustrate the process by which NMR can be used to determine the oil saturation in different Alberta formations.
Geomechanics and Wellbore Stability Design of an Offshore Horizontal Well, North Sea
Authors: Collins Patrick M. 
Published: December 2007

Abstract
This paper describes a comprehensive geomechanical assessment of the P2-NE Field in the North Sea. The objective was to review the available core, log, and drilling data to characterize the geomechanical performance of the P2- NE Field in order to explain observed behaviour, and extrapolate this to future drilling, particularly for Well P2-NE- 2 Horizontal. This study focussed on the inclined Well P2- NE-2 Pilot, which was drilled specifically to obtain reservoir data for the subsequent horizontal well. The geomechanical analysis is based upon the general geological setting, deductions made from field data, and geomechanical core tests. Wellbore stability analyses were conducted, using the mechanical properties and regional stresses as input.
Geomechanical tests and petrophysical logs were used to obtain realistic profiles of mechanical properties. Anomalously, the reservoir mudstones were of considerable strength, exceeding the strengths of the sandstones. Weak zones were found in the sandstone that would be stable while drilling if an adequate mud weight were used. These zones would likely be sand producers during production. This is because the rock stresses would continue to increase, due to the continued pressure decline during depletion.
To obtain stress data, a minifrac test from an adjacent field was analyzed. This provided the breakdown pressure, fracture propagation pressure, the ISIP, and most importantly the fracture closure pressure. The principal horizontal stress orientations were determined from borehole breakout analyses, and compared to residual strain relaxation tests on core. Other observed borehole elongations included wellbore washouts and keyseating. Finally, a stability analysis was conducted for the horizontal well, in order to assess the effect of increasing the mud weight.
Pore Network Modelling of Heavy Oil Depressurisation: a Parametric Study of Factors Affecting Critical Gas Saturation and 3-Phase Relative Permeabilities
Authors: Bondino I. , McDougall S. R. , Hamon G. 
Published: December 2007

Abstract
This study deals with the application of pore-scale network modelling techniques to depressurisation in heavy oil systems. A 3-phase simulator has been developed to account for the fundamental steps of such a depressurisation process, from the nucleation of embryonic bubbles, to their growth by solute diffusion and expansion, to the final stages of coalescence, migration, and production. The model is utilised to examine the impact of a variety of different physico-chemical properties — including bubble density and gas-oil diffusion coefficient — and different depletion strategies upon critical gas saturation and 3-phase relative permeability. Results pertaining to heavy oils are also compared to those from light oil depressurisation simulations and a number of important differences are highlighted.
The first sensitivity analyses heavy oil depressurisation under conditions of instantaneous and progressive nucleation (IN and PN). In the first scenario, the evolution of gas is characterised by embryonic bubbles that are nucleated randomly soon after the bubble-point pressure is reached. In the case of PN, a stochastic algorithm has been developed from related experimental observations. This models the progressive nucleation of additional bubbles as a function of local supersaturation (characterised by pore-scale variations in dissolved gas concentration). It is shown here that IN and PN observations are not necessarily contradictory — the model reconciles the two phenomena and shows how each relates to the underlying experimental parameters.
The vast majority of depressurisation studies reported in the literature to date have tended to focus upon light oils and binary systems. However, the rather different characteristics of heavy oils — high interfacial tension, low gas-oil ratio, high oil density — suggest that such studies may not be particularly representative of heavy oil depressurisation. In order to investigate this issue, a second set of sensitivity analyses is performed, whereby the network model is used to compare critical gas saturations and relative permeabilities arising from the depressurisation of light and heavy oils. It is found that substantial differences can arise in the two systems — in particular, the high interfacial tension of heavy oils is found to lead to a more compact, capillary-dominated pattern of gas evolution than that observed in light oils. As a consequence, improved recoveries (with higher critical gas saturations) are predicted for some heavy oil systems.
Hamaca Heavy Oil Project – Lessons Learned and an Evolving Development Strategy
Authors: Gipson Larry J. , Owen Rex , Robertson Carlon R. 
Published: December 2007

Abstract
Petrolera Ameriven (PA), an operating agent owned by Phillips Petroleum Company, Petroleos de Venezuela, S.A. and ChevronTexaco, is developing the Hamaca extra-heavy crude oil project in the Orinoco heavy oil belt of Venezuela. This project encompasses a development area of more than 250 sq. mi. and will produce more than two billion barrels of 8 API crude and upgrade it into a 26 API product over the 35-year project life.
Numerous single and multi-lateral horizontal well designs have been employed in the initial drilling phase and many of these wells have employed the use of openhole "fishbones". The paper discusses the performance of the various well types and outlines PA’s criteria and strategy for future well designs. Also discussed are the history of the Hamaca development, the use of real-time openhole log data superimposed on 2D and 3D seismic displays for geo-steering and the evolving development strategy of the Hamaca project.
The Hamaca project is the fourth in a series of large scale integrated extra-heavy crude production and upgrading projects being developed in the Orinoco heavy oil belt. An extensive front-end engineering and facility design effort was used to optimize project performance. Through use of the latest technological developments and application of best practices from other Faja heavy oil projects, the field is being successfully developed with an aggressive project schedule.
Stress-Induced Permeability Anisotropy in Fractured Reservoir
Authors: Du J. , Wong R. C. K. 
Published: December 2007

Abstract
The dependence of permeability on direction, or permeability anisotropy in fractured reservoir has been confirmed by many field studies. In practical reservoir simulations, this is accounted for by the introduction of three principal permeabilities and three mutually orthogonal principal axes. This paper investigates whether this is an appropriate approach in analyzing anisotropy of naturally fractured reservoir, which is characterized by heterogeneity and anisotropy due to the fracture’s closure and varied orientation. It is shown that the deformation of the fracture resulted from the change in effective stress may cause the permeability tensor offset an angle to the coordinate axes. Under such circumstance, the conventional simple anisotropy model, which does not consider the cross permeability effect, could result in significant error in interpreting the well response. This paper also studies the stress-displacement behaviour of the fracture and presents a non-linear model, which can be used to well describe the closure process of the fracture under changes in effective stress. Finally, a comprehensive coupled model is proposed to carry out the coupling analysis of the geomechnical-reservoir model. The proposed model has the advantage of enabling the full permeability tensor and non-linear deformation property of the fracture to be taken into account.
Visualization of Sand Structures Surrounding a Horizontal Well Slot During Cold Production
Authors: Meza B. , Tremblay B. , Doan Q. 
Published: December 2007

Abstract
A better understanding of the flow of sand and oil into slotted horizontal well liners is important for both thermal and non-thermal heavy oil production.
The objective of this study was to investigate the structures that might form in, and around a slot when sand production stops and to relate the development of these structures to the porosity and therefore, permeability increases within the sand pack. The parameters studied were: slot size, sand morphology and grain size distribution. Sand production experiments were carried out in a physical model using slotted plates of different sizes. Thin section analysis and X-ray computed tomography (CT) techniques were used to observe sand packs immobilized with epoxy resin after sand production took place.
The results suggest that sand production through the slots can be controlled, depending more on grain sorting than on the morphology of the grains or its average diameter. For a given sand type, sand production behaviour was strongly influenced by the arrangements of the sand grains observed in the vicinity of the slot, including the formation of sand bridges, arches, or plugs. X-ray CT images showed that non-uniform porosity increases occurred in the pack, specifically in the area near the slot, when sand production took place. The porosity increases were less significant away from the slot. The magnitude of this increase was observed to depend on the quantity of sand produced and on the morphology of the sand. Good agreement was found in terms of porosity change between the thin-section observations and the CT scanned images taken of the core before thin-section preparation.
Examination Of Thermally Efficient Steam Injection Techniques For Deep Reservoirs
Authors: Fox R.L. 
Published: December 2007

Abstract
The physical phenomena which limit the depth for economic enhanced recovery of heavy oil by steam injection are individually examined. The ability of techniques for thermally efficient delivery of surface generated steam to address these phenomena is analyzed. Experimental test facilities for comparison of various approaches to improving thermal efficiency developed through the Department of Energy's Project DEEP STEAM are described.

Introduction
The enhancement of oil production through steam injection has been applied to a variety of heavy oil reservoirs. The most economically successful application has been to shallow reservoirs (less than 1000 ft in depth) that are pressure depleted. The reservoirs are responsive to steam enhanced recovery and account for practically all the current domestic production. It has been demonstrated that production. It has been demonstrated that steam drive recovery can be successful to depths of 2500 - 3000 ft (760 - 915 m) however, the production costs are much greater than for the shallow reservoirs. The increase in cost of drilling and completing deeper wells accounts for only a small fraction of total cost increase with depth. A variety of physical effects contribute to reduction in physical effects contribute to reduction in the efficiency of production, these includegreater heat loss during deliveryloss of steam quality at the sand face,reduction in specific volume of the vapor phase,change in the two phase enthalpy distribution, andlower permeability of reservoirs.
Some of these effects can be addressed by modifications of existing steam injection technology. The first two of the above effects can be reduced by application of thermally efficient injection techniques. The work described in this paper is part of the Department of Energy's Project part of the Department of Energy's Project DEEP STEAM. The objective of the project is to reduce the Cost of steam recovery from deep reservoirs through application of technology. There are several tasks covered by the project, including modification of delivery processes for surface generated steam and development of methods for production of steam at the sand face. This paper will initially examine the physical processes which contribute to increased production cost with depth, then will present test facilities developed through the DEEP STEAM, project for comparative testing and project for comparative testing and development of components for improving the thermal efficiency of well completions.
Decision Making In Deep Sea Development Projects
Authors: Goren Yoram , Potter W. Taylor 
Published: December 2007

Abstract
This paper describes the correct process for making decisions on large process for making decisions on large projects. Recent projects in the North projects. Recent projects in the North Sea were subject to an undetected scale effect which resulted in their getting off-schedule and over-budget. This paper proposes an effective organisational proposes an effective organisational set-up and suggests that a management scheme should include a "feedback" function which will form the basis for top level decision making and will enable the project managers to exercise control over their project.

Introduction
The use of the word "billion" (in this paper meaning one thousand million) in paper meaning one thousand million) in normal conversation amongst technical men in the petroleum field, as a means of describing the magnitude of construction projects, dates from approximately 1967. projects, dates from approximately 1967. The Alyeska pipeline was one of the first genuine "macropojects". Today, such projects are considered normal in the projects are considered normal in the petroleum construction industry. That petroleum construction industry. That the incidence of such projects will increase in frequency, as well as in size, is shown by trends in the industry, in the technology and in their cost.

Industry Trends
– Socio-political considerations make it imperative for the Western economies to become increasingly self sufficient in oil and gas. – Exploration and production will move to deeper waters and more hostilese a environments. – Northern ice regions have shown promise of large commercial hydrocarbon deposits. – Development of marginal fields will increase and especially those in close proximity to large fields. – Early production systems are being seriously considered in order to alleviate the financial pressures of large fields development

Technological Trends
– Large structures will be used only for very large fields. – Small or floating structures will be used in conjunction with sea floor equipment installations. – Offshore storage and loading terminals will be installed in increasing numbers. – New technology will continue to be generated and implemented for work in offshore ice regions. Exploration production and transport methods will be developed for all water depth, ice depth and seasonal conditions.

Cost Trends
– Crude and gas price rates increase lag seriously behind inflation. – Macroprojects costs are high (Southern North Sea construction costs have misled managers into under-estimating Northern North Sea costs. In fact, the effect of the increased waterdepth on costs was to increase them by the cube of the depth ration.
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The Semi-Submersible Crane Vessel "Balder"
Authors: Heerema P.S. , Michelsen F.C. 
Published: December 2007

Abstract
The extreme weather and sea conditions of the Northern North Sea and the consequential generally low performance rate of crane ships and barges in general, particularly during the winter months, has led to the concept design and construction of the very large semi-submersible crane vessels which are now being brought into service.
This paper describes the important features of the S.S.C.V. 'Balder' with emphasis placed on its functions as a floating foundation of heavy lift cranes.
Some details of an analysis of the workability rate of the Balder is given. A comparison of this rate with that of a conventional crane ship clearly indicates the operational advantage of the vessel.

Introduction
During the past 7 – 8 years we have witnessed a rather astounding increase in the lifting capacity of the offshore derrick. This development has run parallel with the call for equipment capable of lifting ever-increasing loads. The largest offshore crane in use today can handle a maximum of 3000 short tons. Any further increase in crane size can only be expected to give a negligibly small improvement in the performance of the crane ship.
The principal reasons for this are the relatively large motion responses of the crane ship to the seaway and the stringent limitations on motions imposed by the cranes. Thus, the crane ship or crane barge is one of the most weather bound vessels employed in offshore construction. One therefore arrives at the conclusion that to substantially improve the efficiency of the crane vessel, one needs to look for a different crane support base than that offered by the conventional barge or ship. The incentive to do so becomes even more evident when considering the critical aspects in terms of costs and time which the installation of production facilities in hostile waters represent.
Development Of The Beryl A Field
Authors: Marcum B.L. , Al-Hussainy R. , Adams G.E. , Croft M. , Block M.L. 
Published: December 2007

Abstract
Development drilling from the Beryl 'A' Platform has been in progress for over two years. A total of twelve wells nave been completed with two more nearing completion. Drilling has been concentrated on delineating the Upper Beryl Reservoir, which represents the main producing horizon. Gas injection was started in November 1977. To date, injection performance of the Upper Beryl has been encouraging and producing performance indicates a favourable gravity segregation producing mechanism is operative.

INTRODUCTION
The Beryl Field is located in Block 9/l3a, 95 miles southeast of the Shetland Islands, in U.K. waters. Figure 1 shows location of the Beryl Field relative to other North Sea Fields. Mobil North Sea Ltd. is operator for the Block 9/13a group, which includes Amerada Hess, North Sea Inc., Gas Council (Exploration) Ltd. and British National Oil Corporation.
The Beryl Field discovery well, 9/13-1 (551) was tested from a Jurassic sand at 10,000 feet in September, 1972. Well 9/13-2 was drilled in 1973 and tested a Triassic sand. Figure 2 shows the location of these two wells. Economic analyses, based on seismic mapping and the first two wells, indicated the field was commercial and a concrete gravity base ('Condeep') platform was ordered in July, 1973. Two platform positioning wells, 9/13-5 and 9/l3-6A, were drilled prior to platform tow-out.

BERYL 'A' PLATFORM
Beryl 'A' platform was towed-out and set in 390 feet of water in. July, 1975, less than 24 months from contract award. In September, 1975, an articulated loading column was set about one mile from the platform and tied into the 900,000 barrels of storage in the platform base by a 32 inch pipeline.
Original design concept for the Platform was to provide a capability for extra producing facilities to serve as a central processing, storage and loading point for other expected discoveries in Block 9/13. Current oil and gas handling capacity is 300,000 BOPD and 150 MMCFD respectively. Gas handling capacity can be expanded up to 300 MMCFD by adding additional gas compressors. Pertinent data on the Beryl 'A' platform has been published.(1)

DEVELOPMENT DRILLING
Development drilling from the platform was initiated with one rig in February, 1976 and with the second rig in April, 1976. First production on the platform was in June, 1976, about 44 months from field discovery date. As of June 1978, twelve platform wells have been drilled and completed with two other wells drilling in the Jurassic. In addition, discovery well 9/13-1 was completed as a subsea producer and tied back to the platform in July 1976.
There are 40 well conductor slots on the Beryl 'A' platform. An estimated area of about 5500 acres will be developed by wells directionally drilled from the platform. This is based on the estimated productive area within an assumed 11000 foot drilling radius around the platform, shown as the Beryl 'A' Area on Figure 2.