bluuebunny/crossref_metadata_2025 huggingface dataset:
Analysis of Horizontal Casing Integrity in the Valhall Field
Authors: Pattillo P. D. , Kristiansen T. G.
Published: December 2007

The Valhall field, located in the Norwegian Sector of the North Sea, is a high porosity chalk field characterized by its weak reservoir rock. Global field behavior during depletion includes extensive compaction and associated subsidence.

One highly successful completion alternative, horizontal wells, was, in its early application to Valhall, plagued by the premature failure of the production tubulars associated with reservoir draw down/compaction. Numerical modeling, with subsequent field implementation, has shown, however, that casing with sufficiently low diameter:thicknesses can withstand the rigors of draw down and associated formation loads. Unfortunately, the use of thick-walled casing presents its own difficulties in terms of installing the string (torque/drag) and the subsequent limitations on tool diameter (smart well completions, for example) associated with the stout cross section. Further, a one-size-fits-all doctrine is not optimal, in that the porosity, and therefore strength, of the reservoir rock varies laterally, thus penalizing well designs on the flanks of the reservoir where the chalk porosity is lower and chalk strength is, therefore, higher.

The current paper addresses the above issues by modeling the behavior of the wellbore and surrounding region. Starting with the virgin reservoir, the model considers (sometimes extensive) pre-wellbore depletion, drilling the wellbore, installation of casing and cement, and subsequent draw down. Significant variations to the model include the cross section of the production casing, the quality and quantity of the cement sheath and the perforation pattern. Behavior of these various configurations during subsequent draw down permits them to be ranked according to the life expectancy of the resulting completion. The discussion is enhanced by field results, as several of the completion alternatives have been installed in Valhall wellbores.
Rock Mechanics and Wellbore Stability Analysis While Drilling using LWD Sonic, Density and Caliper Measurements
Authors: Boonen Paul , McElhinney Graham
Published: December 2007

The art of rock mechanical and well bore stability analysis has moved to the real-time domain with the use of Logging-While-Drilling tools. Rock mechanical analysis based primarily on sonic logs (compressional and shear slowness) is a well established technique to identify wellbore stability issues. Logging-While-Drilling logs are slowly replacing wireline logs in large numbers of wells. Not only has the LWD data quality equalled wireline data quality, these data are now available in real-time while drilling. The rock mechanical analysis previously restricted to post drilling analysis, can now be done while drilling. The typically required sonic data (DTP and DTS), the bulk density and a shale indicator are sent to surface in reasonable time increments and the rock mechanical evaluation programs are installed on the rig site LWD systems. Alternatively, the data can be sent to service company or oil company's offices and analysis performed there.

In addition to traditional rock mechanical computations, a new technique is introduced to evaluate borehole break-out and its orientation while drilling using an LWD caliper measurement. The LWD caliper tool used in the North Sea examples employs three ultrasonic transducers to measure the stand-off between the logging tool and the borehole wall. The caliper is computed from these three measurements. In the new method we fit an ellipse through the three measurements and compute the minimum and maximum axes of this ellipse. With the tool face information provided by the LWD survey tool, we can compute the orientation of these axes. Where borehole breakout is resulting from stress relieve at the borehole wall, the direction of the long axis coincides with the direction of the minimum horizontal stress in the formation. Three dimensional borehole caliper images can be created after logging.
Geomechanical Fault Characterization: Impact on Quantitative Fault Seal Risking
Authors: Jones Richard M. , Dewhurst David N. , Hillis Richard R. , Mildren S. D.
Published: December 2007

Fault sealing is one of the key factors controlling hydrocarbon accumulations and can be a significant influence on reservoir behavior during production. Fault seal is, therefore, a major exploration and production uncertainty that requires a rigid, systematic framework within which to quantify the geological risk of trapping hydrocarbons. One of the key uncertainties in this risking procedure is the breaching of structurally bound traps due to the formation of structural permeability networks. Considering a population of faults and fractures, those that are critically stressed are more prone to act as conduits for fluid transmission. Evaluation and mapping of fault seal breach through such networks involves integration of in-situ stress conditions, pore pressure, fault architecture and fault geomechanics.

Geomechanical characterization of well-lithified fault rocks from the Otway Basin and the Northwest Shelf demonstrates that faults can exhibit significant cohesive strength and that fault reactivation and trap breach is influenced by the development of shear, tensile and mixed-mode fractures. The mechanics of the reactivation process are influenced by grain strength and fault morphology. Mercury injection capillary pressures of cataclastic faults indicate a seal capacity of 2400 psi. Following reactivation, seal capacity is reduced ∼95% due to the development of a highly connected fracture network. The tensile strength of such healed faults allows failure to occur by shear, tensile and mixed mode fracturing. These data suggest simple application of Byerlee's Law may not always be applicable when predicting reactivation induced fault seal failure. Consequently, geomechanical tools used to predict trap breach via reactivation that assume cohesionless frictional failure are likely to significantly underestimate seal reactivation risk.

The impact of structurally risking traps using Byerlee and laboratory-derived fault data is demonstrated using the Fault Seal Risk Web approach. Application of geomechanical fault data results in a significant reappraisal of prospect structural risk due to consideration of fault healing.
Analyses of Sonic Data in an Indonesian Well for Formation Damage, Stresses, and Bedding
Authors: Sinha Bikash K. , Kane Michael R. , Borland William H.
Published: December 2007

To help design the completion of an Indonesian development well, we have carried out cross-dipole dispersion analyses over a depth interval of approximately 500 ft. Dispersion analyses provide estimates of radial extent of formation damage and indicators of stress- and bedding-induced anisotropies. Most of these sections of this vertical well exhibit sand and shale lithology with shear slowness anisotropy ranging from 5 to 10%. Above the angular unconformity in the deeper section of the well, a clean sand interval (Sand A) shows evidence of cross-dipole dispersion crossovers. Crossing dipole dispersions are indicators of stress-induced anisotropy dominating the sonic data. We have developed a new technique for estimating the maximum horizontal SH, and minimum horizontal Sh stress magnitudes using multi-frequency inversion of wideband cross-dipole dispersions. At the mid-point of sand A, we estimate the overburden stress SV=-2278 psi; the maximum horizontal stress SH=-1843; and minimum horizontal stress Sh=-1698. The fast shear direction is NW5 in this depth interval. Radial profiling of formation shear velocity indicates varying degrees of mechanical alteration extending from one to two borehole diameters in the entire depth.

A second clean sand interval B, 300 ft above sand A, shows dipole shear anisotropy on the order of 10%. However, cross-dipole dispersions appear to merge together at high frequencies instead of showing a cross-over. Radial profiling of shear velocity in the two orthogonal directions confirms mechanical damage extending to about 2x the borehole diameter. The near-wellbore region in this interval appears to have deformed (material creep) in an attempt to reduce shear stresses and attain hydrostatic equilibrium. Using the same stress sensitivity coefficients as estimated in the lower sand A, the differential stress (SH-Sh) is estimated to be about 20% larger in the upper interval, than the corresponding value in the lower interval.

The fast-shear direction varies abruptly across the angular unconformity, changing from NW5 to NW75. Below the unconformity, this section exhibits beds with dips ranging from 10° to 30°. Cross-dipole dispersions show significant anisotropy and are non-intersecting at higher frequencies. Non-intersecting dispersions indicate bedding-induced anisotropy dominating the cross-dipole data. We have inverted borehole sonic velocities for four combinations of the TI-shale anisotropy, which can be combined with walk away VSPs to obtain all the shale anisotropy constants. These constants are needed in generating synthetic AVO gathers in anisotropic shale formations. Quantitative estimates of the radial extent of near-wellbore damage in this well suggest that perforations should penetrate deeper than twice the borehole diameter to avoid potential permeability impairment caused by near-wellbore mechanical damage.
Forties CO2 IOR Evaluation Integrating Finite Difference and Streamline Simulation Techniques
Authors: Turan Halil , Skinner Roger , Brand Peter , MacDonald Chris , Grinestaff George , Trythall Robert
Published: December 2007

In September 2000 the Forties Field celebrated 25 years of production. Recovery up to this point is approximately 60% of the original oil in place. The field contains undersaturated oil and is being developed under waterflood. A screening study of Increased Oil Recovery (IOR) options highlighted CO2 injection as technically feasible, suggesting an additional recovery of in the range 5-10% of the initial oil in place (STOIIP), subject to further work on the investment economics of the project and corporate sanction. This paper describes the study of the CO2 injection scheme with a focus on the reservoir simulation workflow.

Various techniques for evaluating the full field benefits of IOR schemes can be used including the Todd and Longstaff approach1 or a coarsely gridded conventional compositional reservoir simulation model. The evaluation presented in this paper builds upon a technique that incorporates detailed conventional simulation results into a full field streamline front-tracking simulation. This method was originally developed by Arco and has been successfully applied in several Alaskan oil fields2.

The technique captures the complex physics of the IOR process through fine scale, 3D, compositional, finite difference simulations of ‘type’ sections of the reservoir (the original method used 2D simulations). Results from these simulations are then used to calibrate ‘recovery’ curves that capture characteristics of oil mobilisation and returned solvent volumes as a function of gas injected. The calibrated curves representing gas injection response are then applied as tracers using streamline front tracking simulation to scale up to full field response.
Data Mining Techniques For Optimizing Fast Track Re-engineering of Mature Fields
Authors: Coste J.-F. , Valois J.-P. , Mouret Cl. , Guittard M. , Baleix J.-M. , Larrouquet F. , Mastin E. , Daniel O.
Published: December 2007

Mature fields have a long production history file, and many other large data sets (static data, pressure, and so on). The challenge is often to select the most promising object (a field in a block, a reservoir in a multilayered field, or an area in a wide field). We present a global approach to solve this difficulty, that uses the concepts of Data Mining. It involves Sampling (gather the data, validate, and select the appropriate level of detail), Exploration (using a large set of graphical tools), Data Management (for production data, extracting production indicators), Modelisation (using for instance the hyperbolic oil production decline equation), and Aid to final decision.

All along, graphical tools and multivariate statistical analysis are widely used and must be carefully designed. The whole of the approach requires a good geological and reservoir experience and a Reservoir and Geological Synthesis (RGS). Three field cases illustrate this fast track approach.
A New Data Integration and Work Process System for Providing Online Real-Time Drilling Collaboration
Authors: Kaminiski Dean H. , Pellerin Nicholas M. , Williams Jevon H.
Published: December 2007

Drilling exploration wells in deepwater or other frontier environments is an inherently expensive process. The effects of non-productive time caused by bad or less informed decisions are magnified in such costly and difficult environments.

A major operator is using the communications, presentation software, and other real-time technologies to build a more effective collaborative team to support its deepwater exploration program in the Gulf of Mexico. The technology to remotely monitor drilling operations has long existed. From its inception, the goal of this Real-Time Operations Center (RTOC) has been to move beyond mere monitoring to participation in the drilling operation.

A team of drilling experts, with an average experience level of 20+ years, was assembled. They were given the tools and facility to have 24/7 contact and visibility with all drilling operations. Additionally, the prospect teams associated with each project began holding their meetings in the Real-Time Operations Center, involving both the rig (via video conferencing) and the expert team in ongoing planning and operational decisions. The shift from the old paradigm of a reactive team gathering to sort out existing problems, to a proactive team focusing on preventing problems has had a major impact on drilling operations.

This paper will describe the technology, people, and processes employed to build this Real-Time Operations Center. The layout of the control room and the integration of the data collection and control/decision making processes will be discussed. The skills required and work processes designed to avoid a feared "big brother" syndrome are described. These steps were taken to overcome people and process issues that can defeat such an initiative. Communication and decision making procedures were outlined, designed, and implemented to facilitate success. Success and the documented value of this project are described.
Integrating 4D Seismic to Optimize Production
Authors: Staples Rob , Hague Paul , Cooke Graham , Ashton Peter , Stammeijer Jan , Jolley Steve , Stevens Tim , Marshall John
Published: December 2007

4D or time-lapse seismic methods have been proven by Shell and many other companies to be a valuable tool for reservoir monitoring and management1–4. In this paper, we use case studies to describe best practise. The main example is a mature field in the Northern North Sea, where continuous drilling of infill wells for two years has, so far, confirmed.the interpretation of remaining oil distribution from the 4D seismic data. In mature fields, where infill wells and sidetracks are targetted at small remaining volumes (where partial water flooding may have occurred), it becomes very important to achieve a good integration of 3D and 4D seismic data with the static and dynamic model. This is achieved qualitatively using new visualisation tools, and quantitatively using simple modelling methods such as 4D wedge modelling or more complex methods such as the generation of full field synthetic seismic. The updating of the reservoir simulator is performed in greater detail with the objective that the prediction remains accurate further into the future. This allows more reliable well targetting years after the acquisition of a 4D monitor survey, thereby reducing the necessary frequency of monitor survey acquisition.
Reserve Analysis for Tight Gas
Authors: Cox Stuart A. , Gilbert John V. , Sutton Robert P. , Stoltz Ronald P.
Published: December 2007

Tight gas reservoirs present unique challenges to the reservoir engineer. Applying classical reservoir engineering techniques to these reservoirs is problematic due to the length of time required to reach pseudo-steady state flow and/or establish a constant drainage area. This leads to an inability to accurately estimate the recoverable reserves in a timely and consistent manner. This paper focuses on reserve estimation techniques for tight gas reservoirs.

Both decline curves and material balance methods were found to have serious drawbacks when applied to tight gas reservoirs that had not established a constant drainage area. Gas production analysis (GPA) utilizing a combination of the decline curves and material balance in conjunction with classical pressure transient analysis was found to be more accurate in determining reserves.
Evolving New Stimulation Process Proves Highly Effective in Level 1 Dual-Lateral Completion
Authors: McDaniel B. W. , Surjaatmadja Jim B. , Lockwood Larry , Sutherland Rod L.
Published: December 2007

Key Production Co. began using short-radius, moderate length openhole horizontal lateral recompletions in re-entries of wells in a limestone/dolomite reservoir in northwest Texas. They found that a few wells needed some type of stimulation to achieve optimum production rates. A dual lateral (90° opposed) was drilled on one re-entry to improve production performance. This well was in an area of the field with below-average reservoir quality, and production rates were still disappointing even with two lateral sections. Fracture acidizing was the most likely method to achieve the degree of stimulation needed. There was concern that this might lead to unwanted communication with the aquifer zone below the oil column. Conventional stimulation methods could not achieve multiple, well-spaced, limited-sized fractures.

The operator used a new hydrajet-fracturing technology that has shown a very high success rate in other areas to achieve the stimulation needed for this well, and at acceptable cost. Six separate fractures were placed at selected locations along each of the two lateral sections (12 distinct fractures) in less than 8 hours from first pumping to final displacement. The resulting production rates far exceeded the operator's expectations. This paper presents a brief review of the hydrajet-fracturing stimulation process and specific details related to its highly successful application in this Level 1 dual-lateral completion.
Characterization of Partially Sealing Faults from Pressure Transient Data: An Artificial Neural Network Approach
Authors: Aydinoglu G. , Bhat M. , Ertekin T.
Published: December 2007

Well testing is an effective and convenient tool for characterizing the hydrocarbon reservoirs. Although, the forward solution part of the well testing theory is well advanced, the corresponding inverse solution protocols especially for the complex domains are not well established. In this paper, a new inverse solution methodology, which utilizes the artificial neural network technology in analyzing the pressure transient data, is presented. The proposed methodology is applied towards analyzing the pressure transient data collected from an anisotropic faulted reservoir. The network development begins with a simple system and the level of complexity of the system is increased as the investigation progresses. The final goals of the analysis include determination of the principal permeability values, porosity of the reservoir, distance to the fault, orientation of the fault with respect to the flow directions and the sealing characteristics of the fault. The primary goal of this work is to test the capability of the ANN methodology as an engineering tool in pressure transient analysis applications.
Computational Fluid Dynamics (CFD) as a Tool to Study Cutting Transport in Wellbores
Authors: Bilgesu H. I. , Ali M. W. , Aminian K. , Ameri S.
Published: December 2007

In a drilling operation hole cleaning plays an important role. Improper hole cleaning can lead to problems like reduced penetration rate, torque and drag increase, and increase in pipe sticking potential. Cutting transport in a wellbore is a complex problem affected by several parameters such as mud density, cutting size and density, rate of penetration and mud circulation rate. Researchers conducted experiments with different setups representing annulus flow in a limited number of hole sizes to investigate the contribution of several physical and operating conditions. Due to time and cost involved in the construction and conduction of the experiments all reported studies are limited to physical model dimensions and operating parameters.

In this study, we introduced a new approach to determine the parameters affecting cutting transport in any wellbore. This method utilizes a Computational Fluid Dynamics (CFD) software program. The effectiveness of selected program was determined by simulating successfully results from an experiment reported in literature.

Presented in this study are the effects of cutting and mud properties on the cutting transport efficiency for vertical and horizontal wellbores. This approach eliminates the need for expensive laboratory setups and can be used to study unlimited number of physical and operational conditions in any wellbore.
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

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

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

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

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

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

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

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

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

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

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.
Shallow Seismic As An Aid To Locating Offshore Installations
Authors: Huysinga J.K. , Biddle A.R.
Published: December 2007

The geotechnical characteristics of the North Sea soils are often highly variable even over small distances.

To derive a three-dimensional picture of an area earmarked for platform location is only possible by integrating seismic data and information from soil borings.

This information is needed to select the best location for the structure and to optimise its design.

INTRODUCTION

The final choice of location for the placement of large production platforms in the North Sea is mainly dependent upon the size, depth and lateral extend of the hydrocarbon-bearing reservoirs. However, the soils of the North Sea have been found to be highly variable and often weak in geotechnical terms at shallow depths. This variability in soil types makes it imperative that optimum sites, from an engineering design and installation viewpoint, be found for a particular structure under consideration.

It has been shown that a small shift of a platform site can have a considerable impact on both type of platform and the costs involved in construction and installation. Geophysical techniques have been used in an attempt to determine the lateral continuity of soil layers revealed in site investigation borings. Problems of inadequate seismic resolution and penetration have had to be contended with but it has been found that provided the appropriate tools to suite a particular soil stratigraphy are selected much useful data can be obtained to aid platform site selection. This effort has stimulated the development of new shallow seismic tools and recording techniques which have improved the capability of the industry. This paper describes methods used in the North Sea to obtain the soil data needed for platform location selection and stresses the need for good consultation between the reservoir engineering team, the soil specialists, and the construction engineering team before a final decision on the platform site is take.

RESERVOIR UNCERTAINTIES

Experience in the North Sea. has shown that there is a certain amount of flexibility (sometimes as much as lkm) in locating a platform when only the optimum drainage pattern of the reservoir is considered. The drainage area of a single platform varies in diameter from 6 to 8 km depending on the depth of the reservoir. For fields whose areal extent in one or more directions is larger than the maximum drainage circle and for fields which are much smaller than this circle there is usually no unique optimum platform site.

For nearly all fields in the North Sea there is an even greater apparent freedom of choice if one realises that at the time when a decision for the site has to be taken the field is generally still not well defined. Small shifts of the location of the platform can there fore nearly always be absorbed in the flexibility allowed in the development plan of a given field.
Garoupa Subsea Production System
Authors: DeJong J. , Adamson S.M.
Published: December 2007

The Garoupa production system installed offshore Brazil for Petrobras is now onstream. This system represents one of the most ambitious undertakings of its kind. The nine subsea wells are completed using a dry one-atmosphere chamber system supplied by Lockheed Petroleum Services (LPS). Well production flows to a Petroleum Services (LPS). Well production flows to a seabed dry manifold centre where it is controlled and manifold. Pipelines connect the MC to a mooring tower to which a converted tanker is moored for processing of crude and its temporary storage. A second mooring tower provides for tanker transport of crude to land. provides for tanker transport of crude to land. Installation of the subsea equipment is described. Flowline bundle and pipeline and start-up progress to March 1979 is described and some of the problems encountered their solution and impact on project schedule are discussed.

Introduction

The Garoupa field seafloor production system installed by the Brazilian National Petroleum Company. Petroleo Brasileiro S.A. (Petrobras), is the largest and most ambitious subsea production project initiated to date. The field, which is located 250 km. east-northeast of Rio de Janeiro, and 80 km offshore, (see Fig. 1) was discovered in November 1974. Further drilling proved it to consist of two separate structures, the northern Garoupa field and the southern Namorado field. The subsea production system is installed in water depths between 120–166 m. (394–544 ft). The system (Fig. 2) consists of:nine one-atmosphere wellhead chambers (WHC)supplied by Lockheed Petroleum Services.a nine-well one-atmosphere manifold centre (MC)supplied by Lockheed Petroleum Services.an electro-hydraulic control system supplied by Cameron Iron Works.