bluuebunny/crossref_metadata_2025 huggingface dataset:
A Successful High-Temperature Gel System To Reduce Steam Channeling
Authors: Eson R. L. , Cooke R. W.
Published: December 2007

A new high temperature gel system has been developed and successfully demonstrated in the field to reduce steam channeling and override in mature thermal projects. During the past three years a program has been underway in the laboratory and in several heavy oil fields in California, in an effort to develop a family of gels that can be injected in relatively small volumes (<600 barrels) into pre-existing steam channels and/or override sections within an active steam project. These inexpensive (< $15,000) gel treatments are applied with only a minimum amount of well downtime, typically three days, or less, and have demonstrated the ability to divert steam and increase oil recovery rates for up to a year and more. In addition to producing incremental oil, diversion of significant quantities of steam from existing thief zones has resulted in: (1) reduced volumes of live steam produced out casings, (2) reduced casing pressure, (3) a definite heat redistribution in the reservoir, (4) decreased flow line temperatures, (5) reduced well pulling and pump repair costs and (6) increased life in both injection wells and producing wells.

This paper describes the typical treatments completed in four of California’s largest heavy oil fields and five different reservoir sand bodies. Data and discussions regarding the treatment methodology, monitoring tools and techniques, as well as the technical and economic evaluations are included. Despite the fact that many of the treatments were completed with heavy oil prices at, or near $10 per barrel more than 70% of the treatments were economic successes on incremental oil production alone. An example of one treatment is provided which produced more than 18,000 barrels of incremental oil in the first six months following the treatment.
Applications of Pressure-Interference Data in Reservoir Characterization Studies, Big Horn Basin, Wyoming
Authors: Haws G. W. , Hurley N. F.
Published: December 2007

Extensive pressure-interference testing in seven Big Horn Basin anticlinal traps shows that directional permeabilities have a dominant northeast trend. This trend is roughly perpendicular to anticlinal axes. Core studies, an outcrop-derived fracture model, and studies of regional groundwater flow suggest that high directional permeabilities lie parallel to anticlinal axes. In contrast, drilling-induced fractures and borehole breakouts interpreted from FMS* (Formation MicroScanner) logs suggest that high directional permeabilities lie perpendicular to anticlinal axes. Present-day maximum horizontal in-situ stress, which is oriented roughly perpendicular to anticlinal axes, may control directional permeabilities detected by interference tests.
The Modelling of a High-Permeability North Sea Reservoir Enclosed by Faults
Authors: Vik S. A. , Selseng Harald
Published: December 2007

This paper presents a well test performed on a high permeability North Sea reservoir producing from a water zone. The test and the following interpretation were designed to be of a conventional North Sea format. However the pressure behaviour from the formation combined with the limited quality of the bottom hole pressures resulted in a complex analysis sequence. The interpretations had to be performed using pressure derivative methods and semilog analysis in combination with pressure history simulations to provide consistent results.
The Use of Observation Wells in Reservoir Management
Authors: Wannell M. J. , Ezekwe E. C.
Published: December 2007

The South Morecambe gas field has benefited from the use of a subsea observation well since 1983. This continues to provide valuable pressure data that have improved both the accuracy and uniqueness of the history match. This paper will concentrate on the use of these pressure data and particularly the use of pressure derivatives to reduce the effect of gauge drift. The paper will also report on the novel subsea technology used, particularly the neutrabaric chamber and acoustic telemetry data transfer. It will contrast results from three electronic gauges, two mounted downhole and one on the mudline.
Measurement of Invasion Using an MWD Multiple Depth of Investigation Resistivity Tool
Authors: Beck G. F. , Oberkircher J. , Mack S.
Published: December 2007

Measurements made with an MWD multiple depth of investigation resistivity tool are compared with wire-line resistivity logs from two wells in the Gulf of Mexico. Where data density permitted, four investigation diameters at three different time intervals were studied using the MWD tool while drilling, the MWD tool after drilling (MAD), and the wireline (WL) logging operations. The MWD tool allowed new information to be gathered about the early stages of invasion, and combined with the WL data, allowed for the study of the invasion process over time.

Both wells encountered gas, oil, and water sands. The observed invasion characteristics were the same as reported elsewhere: invasion volume (on a per foot basis) was relatively constant for a given formation exposure time regardless of formation property or mud overbalance1. A minor exception to this was the higher initial spurt loss observed in gas sands which was attributed to the higher mobility of gas allowing higher initial flow rates into the formation.

Conventional step profile and annular invasion theories cannot explain the observed MWD, MAD, and WL resistivity profiles over time. Instead, a slope profile invasion model with a long salinity transition zone is indicated. The observed data suggests that in the invaded zone hydrocarbons are not flushed to a residual saturation, but at a critical Sw value filtrate flow into the formationis favored over continued hydrocarbon flushing. Therefore, as the invasion volume is spread out over a larger area instead of being concentrated in a small diameter, the actual depth of invasion is greater than those determined by conventional methods that assume a high Sxo value. The resulting effect on log analysis is that conventional models may not accurately determine Rt.
Analysis of Pressure and Rate Transient Data From Wells in Multilayered Reservoirs: Theory and Application
Authors: Bidaux Pascal , Whittle T. M. , Coveney P. J. , Gringarten A. C.
Published: December 2007

A new solution technique is described for the analysis of multi-layered tests. This technique is based on an analytical conversion of a single-layer transient pressure response into a multi-layer response. Formation cross-flow is taken into account and a wide variety of inner and outer boundary conditions are possible. The method is succesfully applied to a field example for which single-layer analysis failed to give consistent results. Regression is used to simultaneously match observed pressures and layer rates. In the absence of measurable layer rate transients, as encountered in the field example, simple flow profile measurements to obtain relative layer production are all that is required to perform a multi-layer analysis.
Buildup Behaviors in Commingled Reservoir Systems With Unequal Initial Pressure Distributions: Interpretation
Authors: Agarwal Bijan , Chen Her-Yuan , Raghavan Rajagopal
Published: December 2007

Pressure behaviors in layered commingled reservoirs that are a consequence of imbalances in initial reservoir pressures are documented. General conclusions concerning the interpretation of wellbore pressures when layer rates are unavailable are noted. A detailed examination of the time period when there is no surface production shows that much information which has a bearing on production performance can be discerned by the observation of pressure behavior during this time period. A number of approximate solutions to aid the analyst in analyzing well responses are documented.

The observations noted here are general in the sense that they can be used to understand long-time shut in behavior even if initial pressures are equal and layers are commingled at different times.
High-Resolution VSP Imaging To Locate Additional Reserves in Producing Fields
Authors: Johnston L. K. , Markowitz Gerald
Published: December 2007

In southern Louisiana many of the mature oil and gas fields are piercement salt domes where geologic structure often results in fragmented, although prolific, reservoirs throughout the fields. Surface seismic and geological data have proven reliable for exploration drilling in these reservoirs. This information, however, is not adequate to define the small fragmented reservoirs encountered in development drilling.

The use of borehole seismic imaging to define structure in exploration wells is a common practice. However, these surveys have typically lacked the accuracy to be used reliably in a development environment. Traditional borehole seismic surveys were adjusted to run inside tubing and inside casing while enhancing the resolution required to make development drilling decisions. By defining the reservoir extent, an operator can confirm economics before additional development drilling.

A case study examines the specific seismic imaging technologies used to define the updip limit of a reservoir from an existing production well. A three-component, multireceiver tool and marine vibroseis source technology were applied with advanced wave field processing to provide the resolution required to meet the objective of defining reservoir extent.
Relating Static and Ultrasonic Laboratory Measurements to Acoustic Log Measurements in Tight Gas Sands
Authors: Tutuncu A. N. , Sharma M. M.
Published: December 2007

A comparison of Young's moduli and Poisson's ratios obtained from ultrasonic laboratory measurements with static moduli obtained under identical stress conditions shows that the Young's moduli are 1 to 6 times higher under ultrasonic loading conditions. A comparison of these two laboratory measured quantities with log derived moduli measured at 20 KHz indicates that Eultrasonic> Esonic > Estatic, The clay content and porosity of the samples varied from 1 % to 54.5% and 3% to 17.5%, respectively. This clearly suggests that a wide variety of sandstones behave in a viscoelastic manner. The magnitude of the variation with frequency is a function of the clay content, grain size, shape of intergranular contacts, mineralogy and fluid saturations. A model is presented that describes this observed viscoelastic behavior.

The measured static moduli are a function of the sample length. This effect is investigated in some detail. The reported static moduli were obtained at L/d ratios of 2. When comparing log measurements to core, two inherent problems were encountered: depth correlation and sample size. These effects need to be properly accounted for when comparing logs with cores.
Defining Flow Units in Dolomitized Carbonate-Ramp Reservoirs
Authors: Lucia F. J. , Kerans Charles , Senger R. K.
Published: December 2007

The problem of defining flow units in carbonate reservoirs has been investigated by integrated geological, petrophysical, and geostatistical outcrop studies. Results show that flow units (mappable intervals with similar petrophysical properties) can best be defined in terms of rock-fabric fades. Geostatistical analysis indicates that the different rock-fabric facies defined are significantly different but that within rock-fabric facies the petrophysical properties are near random. Detailed outcrop mapping shows that rock-fabric units are systematically arranged within genetic packages that have predictable stacking patterns within a sequence stratigraphie framework.
Anguille Marine, a Deepsea-Fan Reservoir Offshore Gabon: From Geology to Stochastic Modelling
Authors: Massonnat G. J. , Alabert F. G. , Giudicelli C. B.
Published: December 2007

The ANGUILLE MARINE field has been produced for 25 years. Implementation of water injection soon revealed complex reservoir mechanisms controlled by severe sedimentary heterogeneities.

The ANGUILLE Formation has been deposited in a deep-sea-fan environment (slope apron) with a low sand/shale ratio. In such an environment, the geometry of sandbodies controls the reservoir connectivity. Knowledge of this parameter is therefore critical in understanding flow mechanisms.

This paper deals with a multi-scale analysis of the heterogeneities (5 scales were studied), and the research of the best way to represent all the scales in the 3D modelling.

Sequence stratigraphy principles are applied successfully and allow the reconstitution of the ANGUILLE Formation history. In each defined time unit, a sequence analysis log data is used to divide the reservoir into four main types of turbiditic geometries (channels, lobes, slumps, laminated facies). Isovalue maps of lobe and channel frequency slow clearly the paleo-directions of sediment supply. These, together with the well data, constrained the generation of fine 3D models of heterogeneities (more than 2 millions gridblocks) using geostatistical techniques. The generated models proved to efficiently represent the reservoir, as confirmed by the drilling of a new well in the northern part of the field, and by the results of the full-field flow simulations.

An attemptto use more precise sedimentary bodies dimensions in the matching of the actual data was carried out, and proved that this characteristic could become one of the usable parameter to match the reservoir performance.
Pressure Transient Parameter Estimation in the Laplace Domain
Authors: Wilkinson D. J.
Published: December 2007

It has become customary to compute pressure transient model solutions in the Laplace domain. This is because it generally simplifies the solution, and allows easy incorporation of wellbore storage, commingled systems or dual-porosity formations. On the other hand, the convolution and parameter estimation are usually done in the time domain. Thus, when the solution is used as the forward model in an optimization scheme, each forward evaluation requires a Laplace inversion of the model (using the Stehfest algorithm) and a time domain convolution. Here we explore the alternative of transforming the data into the Laplace domain (a one-time operation) and then doing the fitting in the Laplace domain. The chief new result is a self-consistent prescription for dealing with the fact that the data are available only over a finite time interval. The technique is illustrated for the case of a conventional well test which reaches radial flow on the time scale of the test, a situation for which the method is particularly efficient.
Effects of Properties in Seismic Data on Reservoir Characterization and Consequent Fluid-Flow Predictions When Integrated With Well Logs
Authors: Araktingi U. G. , Bashore W. M.
Published: December 2007

A reservoir model was generated to quantify the enhancements in reservoir description resulting from the incorporation of seismically-derived information with well-based data and to study how the quality of the seismic data affects those reservoir descriptions. The reservoir model was created from 56 well logs with a predetermined spatial correlation using geostatistical techniques. A regular grid of traces was extracted from this model and transformed into 3D seismic surveys which were then inverted to produce acoustic impedance logs. Several seismic data parameters such as frequency bandwidth, waveform phase estimation error, and correlation coefficient between seismic and well data were varied to study their relative importance on reservoir description and subsequent flow results. These differing seismic datasets were finally integrated with the original well-log data again using geostatistical methods.

Comparative fluid displacements were performed on all reservoir realizations using an all-purpose flow simulator to quantify the flow behavior differences. The results, based on breakthrough time and oil recovery predictions, show that even marginal increases in frequency bandwidth (e.g., increases of 10 Hz in the upper frequency) provide significant enhancements to the reservoir model. Also, estimation of waveform phase to within ±20° of the true value is shown to be sufficient to capture much of the interwell heterogeneity contributed by the seismic data and thus does not significantly affect fluid-flow results. Finally, even for correlation coefficients as low as 0.4, which initially was considered quite low, sufficient positive contribution from the seismic data still warrants integrating it with the well-log data.
Outlook For Oil: The Problems And The Promise
Authors: Ballou George T.
Published: December 2007

Good afternoon, gentlemen…..

I am honored by your invitation to address this distinguished meeting, especially since it gives me an excuse to visit this great producing region once again.

San Francisco and Los Angeles and Chicago and New York are wonderful cities and excellent places to conduct business. But to see the oil business in true perspective you have to return to the San Joaquin Valley or the Permian Basin, or one or the other places where the blood and bone or the industry is formed.

Sometimes I think oil men are like the legendary Greek wrestler, Anteus. He was unbeatable as long as he stayed in contact with the earth—-in other words, as long as he kept his feet on the ground. It wasn't until he allowed himself to be lifted into the air that his opponent, Hercules, was able to do him in.

In the same way, the oil fields—-where the real work or finding and producing oil is done—-are the industry's source or strength. Only by understanding what happens here can the oil business keep its feet on the ground, and be ready for all challenges.
A Coiled-Tubing-Deployed Downhole Video System
Authors: Rademaker R. A. , Olszewski K. K. , Goiffon J. J. , Maddox S. D.
Published: December 2007

This paper describes a fiber-optic downhole video system deployed on coiled tubing. A state-of-the-art inspection system has been developed that combines proven coiled tubing components, innovative cable termination methods, and the latest downhole video and fiber-optic cable technology. This new system has the capability to visually inspect horizontal wells, to displace opaque liquids in the desired viewing area by locally injecting clear fluids, and to obtain high resolution video at greater depths than possible with other camera systems. Testing indicates that this system provides improved versatility and video quality. This paper includes a complete description of the components in the downhole video system.
Field Study: Utilizing a Progressing Cavity Pump for a Closed-Loop Downhole Injection System
Authors: Klein S. T. , Thompson Scott
Published: December 2007

The information contained in this paper is based upon the field test of an experimental closed-loop injection system. The basis of the test was to determine both functionality and future feasibility. The system was installed in an existing water flood where the water source zone and the injection zones were completed in the same wellbore. The two zones were isolated by a bottom packer and a second upper packer, installed above the water source zone, which allowed the casing to be pressure tested to meet state regulatory requirements. The pumping system consisted of a sucker rod driven progressing cavity (PC) pump installed below the bottom packer. The sucker rods and pump rotor were driven from the surface by a variable speed hydraulic drive system. Water from the water source zone entered the pump through a perforated sub in the tubing string above the pump and was pumped into the injection zone. Downhole pressure gauges were initially installed to determine the differential pressure across the pump. A downhole flow meter was later installed to determine actual flow rates into the injection zone.
Large-Scale Laboratory Sand Production Test
Authors: Kooijman A. P. , Halleck P. M. , de Bree Philippus , Veeken C. A. M. , Kenter C. J.
Published: December 2007

This paper describes the results and interpretation of a large-scale laboratory sand production test. In the experiment, a real well with multiple perforations was simulated, using an outcrop rock selected to represent core material from a specific field. The objective of the experiment, which was the first of its kind, was to investigate the influence of both effective stress increase and drawdown on sand production behavior, taking into account the influence of the presence of casing and cement and of perforating. An additional objective of the test was to investigate the influence of a water cut on the sand produced. The laboratory well behaved very realistically, in terms of both oil and sand production.
Hydrates Inhibition by Physical Solvents in the Treatment of Natural Gas From Offshore Reservoirs
Authors: Behar Emmanuel , Creagh Louise
Published: December 2007

The transport of natural gas from offshore producing fields presents difficulties not encountered in conventional onshore situations. If the gas is transported untreated, there is a risk of hydrates formation causing blockages in the pipeline.

A possible remedy is to treat the gas before transport using a compact unit in which it is contacted at low temperature by a physical solvent. The treatment consists of removal of condensate from the gas thus avoiding two-phase flow in the pipeline, removal of sour gas components which greatly increase the hydrates formation temperature, dehydration and depression of the hydrates formation temperature resulting from the inhibiting effects of the selected solvent.

After screening several physical solvents, two were retained for an experimental study of their effectiveness in hydrate inhibition, as well as their ability to selectively remove sour gas components while limiting the losses of hydrocarbons to the solvent. Hydrate formation curves were measured for a synthetic natural gas (s.n.g.) in the presence of water and of solutions of the tested solvents in water. For the sake of comparison, the hydrate formation curve was also determined for the s.n.g. in the presence of a methanol solution since this is the standard hydrate inhibitor in gas transport.
Thermodynamic Modeling for Organic Solid Precipitation
Authors: Chung Ting-Horng
Published: December 2007

A generalized predictive model which is based on thermodynamic principle for solid-liquid phase equilibrium has been developed for organic solid precipitation. The model takes into account the effects of temperature, composition, and activity coefficient on the solubility of wax and asphaltenes in organic solutions. The solid-liquid equilibrium K-value is expressed as a function of the heat of melting, melting point temperature, solubility parameter, and the molar volume of each component in the solution. All these parameters have been correlated with molecular weight. Thus the model can be applied to crude oil systems. The model has been tested with experimental data for wax formation and asphaltene precipitation. The predicted wax appearance temperature is very close to the measured temperature. The model not only can match the measured asphaltene solubility data but also can be used to predict the solubility of asphaltene in organic solvents or crude oils. The model assumes that asphaltenes are dissolved in oil in a true liquid state, not in colloidal suspension, and precipitation-dissolution process is reversible by changing thermodynamic conditions. The model is thermodynamically consistent and has no ambiguous assumptions.
Deviated Well Fracturing and Proppant Production Control in the Prudhoe Bay Field
Authors: Martins J. P. , Abel J. C. , Dyke C. G. , Michel C. M. , Stewart Graham
Published: December 2007

Over 300 hydraulic fracturing operations have been performed at Prudhoe Bay. The available data have been analysed to examine the effects of well deviation and azimuth on fracture treating pressures, job placement success and, most importantly of all, post-frac well performance. Clear conclusions emerge.

Proppant production is an expensive problem at Prudhoe Bay. Factors affecting proppant production are examined, together with the results of a field evaluation of Resin Coated proppant.
Stochastic Models of Reservoir Heterogeneity: Impact on Connectivity and Average Permeabilities
Authors: Alabert F. G. , Modot Vincent
Published: December 2007

Probabilistic techniques are being increasingly used for modelling reservoir heterogeneity. A wide variety of models are now available, which all differ in their underlying assumptions, range of application, complexity of usage and computer efficiency.

Each technique has its own unconditional supporters. However, for the non-specialist, choosing one method is not trivial. Which method is best suited to a particular modelling context? After all, does it really matters from a practical, engineering point of view?

These are the basic questions we are addressing here.

After a review of current heterogeneity modelling techniques, a few "classical" models are compared on data from a deep-sea-fan reservoir. Fine scale, three dimensional distributions of permeability are generated using Indicator Simulations, Gaussian/Fractal Simulations and Truncated Gaussian Simulations. Common well log data and geological a priori are used for all methods.

The models are then compared in terms of connectivity and distribution of average permeabilities at the scale of full-field flow simulation grid.

Connected pore volume geometry on fine grids is found to be quite sensitive to the modelling technique. After upscaling, large scale permeability distributions remain sensibly different. The choice of the stochastic modelling technique has therefore a potentially important, practical impact on reservoir description.
Single- and Two-Phase Flow in Natural Fractures
Authors: Rossen W. R. , Kumar A. T. A.
Published: December 2007

Understanding and predicting the production behavior of naturally fractured reservoirs requires understanding flow in a single fracture. Individual fractures can be represented as two-dimensional networks of locations of wide and narrow aperture. Percolation theory prohibits two-phase flow in such a network under restricted conditions: that is, the relative-permeability curves cross at a relative permeability of zero. Using the Effective Medium Approximation (EMA), we illustrate the effect of aperture distribution and of gravity on these kri curves. In the absence of gravity effects, as the aperture distribution becomes broader, the cross-over point in the relative-permeability curves approaches zero wetting-phase saturation. On the other hand, straight-line relative-permeability curves obtain if gravity segregation dominates flow. This can occur, however, only if both phases are free to attain gravity equilibrium, which may not be possible given the restriction on local two-phase flow. In fractures, viscous forces become significant at pressure gradients orders of magnitude lower than in rock matrix. Viscous effects would tend to lead to straight-line relative permeability curves, as well.

We present also several simple models for non-Newtonian single-phase flow through fractures. Shear-thinning non-Newtonian fluids make the fracture appear to be wider than in Newtonian flow. In addition, plugging a fracture requires a higher fluid yield stress than expected from characterization of fracture aperture from Newtonian flow. Both non-Newtonian effects are greatest for fractures with broad aperture distributions.
Preventing Shallow Gas Migration in Offshore Wells: The Performance of Lead Cements
Authors: Coker O. D. , Harris K. L. , Williams T. A.
Published: December 2007

Offshore drilling operations that encounter shallow gas formations must consider the potential annular gas flow that may occur following primary cementing. Many specialized cements and procedures have been developed to combat gas migration, but the complexities of gas migration control still challenge operators worldwide. In offshore shallow environments, additional complications can arise with the presence of weak formations and cold temperatures. In such conditions, lightweight lead cements are employed to avoid fracturing the wellbore. Although lead cements are often viewed simply as "filler" materials, shallow gas control slurries must far exceed that role as they become the mechanism to help isolate the movement of gas up the annulus.

Presented in this paper is a review of the properties of gas control cementing systems specifically related to lightweight lead slurries. The importance of fluid loss control, rapid gelation, and compressive strength at the time of drillout is stressed. Silica fume cement and newer cementing additives such as colloidal silica and small particle cement are highlighted as means of helping prevent shallow gas migration. Several offshore cementing operations are documented which confirm the success of applying the prescribed designs and methods.
High-Energy Gas Fracturing (HEGF) Technology: Research and Application
Authors: Yang Weiyu , Zhou Chunhu , Qin Fadong , Li Dang
Published: December 2007

HEGF is an oil/gas well stimulation technology by means of propellant inflamming in wells to produce multiple radial fractures in formation and hence to enhance the well production. The paper summarizes the achievements of our effort on research and application of the technology. For understanding the HEGF mechanism, laboratory and field experiments are conducted and numerical simulators are studied. The treatment design method and implementation techniques are discussed. A design software, which includes the content of propellant burn, perforation, stemming liquid motion, fracture propagation, fluid flow in fracture, and production increase prediction etc., has been developed to serve as the basis of the design, optimization, and control of the technology. The application of the technology to exploratory, production and injection wells shows its great prospects in oil and gas industry.
Stimulation of High-Rate Gravel-Packed Oil Wells Damaged by Clay and Fines Migration: A Case Study, Gullfaks Field, North Sea
Authors: Svendsen O. B. , Kleven Reidun , Hartley I. P. R. , Aksnes Norvald
Published: December 2007

This paper reviews the methodology and approach taken to stimulate oil production from high rate gravel packed wells in a high permeability poorly consolidated sandstone reservoir, containing up to 35% clay fines. The three key elements involved were; a detailed laboratory study to identify and quantity the damage mechanism, selection of an optimum treatment fluid system, and finally successful execution through accurate placement of the treatment fluids.
Reservoir Management of the Oseberg Field After Four Years’ Production History
Authors: Fantoft Svein
Published: December 2007

The Oseberg Field comprises an accumulation about 500 × 106 Sm3 of oil and 60 × 109 Sm3 of free gas located in seven partly communicating reservoirs. Oseberg experiences full scale gas injection supplied by water injection in some reservoir units. Production experiences and observation wells have confirmed gravity stable displacement at high offtake rates. History matched simulation models indicate that oil recovery above 60% may be obtained in the main reservoir unite. An extensive horizontal well program will give important contributions to a prolonged plateau period and high recovery.
Transforming the Future of the Brent Field: Depressurisation—The Next Development Phase
Authors: Braithwaite C. I. M. , Schulte W. M.
Published: December 2007

Under waterflood development, gas production from the Brent Field will fall off plateau in 1998 and, at field abandonment, it is estimated that approximately 55% of the 6.9 Tscf GIIP and 54% of the 3600 MMstb STOIIP would be recovered.

With its high solution gas-oil-ratio, reservoir depressurisation, as an enhanced recovery project, is an attractive possibility. In this process, reservoir pressures would be progressively lowered, ultimately to approximately 1000 psi.

It is expected that gas liberated from residual and by-passed oil would increase gas recovery by over 1 Tscf allowing the field to continue to produce at plateau levels into the 21st Century. Depressurisation is also expected to increase oil and condensate recovery by 30 MMstb compared to a continuation of the ongoing waterflood. From a sub-surface viewpoint, the main challenge would be to manage the field to maximise oil recovery while maintaining gas sales at plateau.

To allow the field to move into a new development phase, an extensive platform modification programme will need to be initiated. Planning has to take into account the uncertainties associated with a project that has not been tried on an oil reservoir of such a scale. Aquifer influx, H2S and sand production are some of the risks that have been assessed and contingency measures identified.
Investigation of Optimum Well Spacing for North Sea Eocene Reservoirs
Authors: Matthews J. D. , Carter J. N. , Dake L. P.
Published: December 2007

Eocene reservoirs contain thin columns of high viscosity oil. Recovering the oil is difficult because coning results in low oil production rates.

This paper examines the effect of drilling wells on a much smaller spacing than is traditionally employed in the North Sea. It is found that smaller spacings improve oil recovery.
The Bruce Gas Export Line Tie-In Into the Frigg UK Line by Means of the Tomseal Isolation Technique
Authors: Freund J. P. , Vossier Bernard
Published: December 2007

The Bruce field is a large gas condensate accumulation, which underlies blocks 9/8a, 9/9a and 9/9b in the UK sector of the North Sea. The decision to develop the Bruce field was taken by the Bruce Partners (BP Exploration, Elf UK, Total Oil Marine, Hamilton and LASMO North Sea) in 1989, and the responsibility for gas transportation was assigned to Total Oil Marine, as operator.

In November 1989, TOTAL formed a project group, which was set up to study, design, construct and install the Frigg UK Wye Project, besides other responsibilities within the Bruce Area Development Project developed by B.P. In the actual economic context calling for cost effective developments, the project group conceived, engineered, tested and deployed a new pipeline isolation philosophy: TOMSEAL, which is based on a combination of proven hot tapping and folding stopple techniques associated with the development of new remotely controlled plugs, for the tie-in of the Wye piece into the Frigg UK line. TOMSEAL makes lengthy recommissioning redundant as it avoids the need for pipeline flooding, dewatering and drying, therefore generating cost savings on the connection operations but, more importantly, shortening dramatically gas export transportation system unavailability when performing the connection.

Once the works are commissioned in 1993, gas will be exported from the Bruce field through a new 32-inch pipeline 5.8 km long which is now connected to the 32-inch Frigg UK line and on to St Fergus terminal in Scotland. The pipeline connection is through a subsea Wye component which has been tied into the Frigg UK line. The preparation works commenced in December 1991 and were completed in April 1992. The installation and isolation works were successfully performed in Summer 1992.
New Subsea Developments in a Mature Area: Planning for Access
Authors: King G. W. , Miller B. L. , Thomas P. V.
Published: December 2007

In a mature development area such as the North Sea the addition of new small scale subsea developments can have a significant economic impact. Such fields are frequently developed using the infrastructure and services of an existing development. The paper considers a critical aspect of this pattern of developments: the need to include and maintain access for moored vessels within the development area with regard to the increased number of seabed flowlines.

The situations where access with a moored vessel are considered: at the new development; along the flowline route and at the platform facility. The problems of access are then addressed analytically and solutions presented for ‘design for clearance’ and ‘design for contact’ conditions. The technologies which could be used for these conditions are then discussed with regard to technical limitations and economic considerations.
The Greater Ekofisk Area: Addressing Drilling Fluid Challenges With Environmental Justifications
Authors: James R. W. , Helland Bjørn
Published: December 2007

This paper discusses the drilling related complexities of the Greater Ekofisk basin which have demanded innovative shale stabilizing mud systems. The innovative mud systems discussed include "pseudo and synthetic" oil emulsion fluids; and cationic water based fluids. Phillips Petroleum Company Norway (PPCoN) has improved drilling fluids standards and drilling/wellbore performance with environment awareness.

The environmental evaluations of the innovative drilling fluids have involved a series of studies including Acute toxicity; Bio-degradability; and Bio-accumulation. In addition, marine seabed surveys have included studies to trace drilling fluids in the sea bottom sediments. The studies have revealed weaknesses in some test procedures. Through cooperation with external research laboratories, alternative test methods have been developed and evaluated.
The Application of High Flow Rate Well Testing Techniques on Precompleted Subsea Oil Wells
Authors: Jewell Stephen , Home Hugh
Published: December 2007

This paper describes the design and performance of a temporary surface welltesting system capable of processing up to 20,000 BOPD. The system was designed to meet the requirements for the post-completion testing of subsea oilwells on a North Sea development. The paper will be of interest to engineers wishing to achieve high flowrates during testing operations on semi-submersible drilling rigs.
Low-Energy, High-Reliability Platform for Gasfield Development
Authors: Fomiatti Stefano
Published: December 2007

A new approach in the definition of production & service units and in the operating management of platforms installed in the peripheral and marginal gas fields in the Adriatic Sea, is being developed in order to reduce investment & operating costs. The platform's new typology defined as BEAF (Low Energy - High Reliability), should reach the intervention and maintenance objective every 6 months by means of reduced production plants and highly reliable components.
Screening of WAG Injection Strategies for Heterogeneous Reservoirs
Authors: Surguchev L. M. , Korbøl Ragnhild , Haugen Sigurd , Krakstad O. S.
Published: December 2007

Microscopic oil displacement and sweep efficiency of waterflooding and continuous gas injection can be improved by water alternated gas (WAG) injection.

Reservoir and fluid properties are determining factors in screening WAG injection strategies. Evaluation of miscibility condition is an important step in the process design. Different correlations used for miscibility evaluation are compared on the Brent reservoir example. The effect of injection parameters on injectivity and recovery in the layers of a stratified reservoir is shown through the simulation results.

Methods improving WAG efficiency like non-stationary injection are discussed. Main parameters of cyclic injection with variation of flow directions are considered in relation with non-stationary WAG. Numerical modelling with respect to three phase effects showed the advantages of non-stationary WAG in a stratified reservoir.
Examining the Potential for Corrosion Inhibitor and Scale Inhibitor Compatibility in a Multifunctional Squeeze Strategy
Authors: Lawless T. A. , Bourne H. M. , Bolton J. R.
Published: December 2007

The molecular requirements and the fundamental physico-chemical mechanisms associated with inhibition of both scale and corrosion are reviewed establishing the general difficulties associated with the provision of single component, dual function agents. Molecular groups, steric effects, ion binding, conformational needs, ionisation and molecular weight are viewed theoretically to describe molecular demands on performance. An array of commercially available scale and corrosion inhibitors have been examined for their bulk and low concentration solution compatibility prior to the generation of detailed phase behaviour maps to elucidate realms of binary component coexistence. A compatible pair of inhibitor agents were selected for dynamic coreflood retention and release investigations, at elevated temperatures, to probe likely squeeze characteristics. Both single component and dual component formulations in adsorption only and precipitation modes were studied in detail. Desorption curves were successfully modelled with non-equilibrium models to help quantify operational mechanisms and identify future directions.
Efficient Iterative Linear Solution of Locally Refined Grids Using Algebraic Multilevel Approximate Factorizations
Authors: Wallis J. R. , Nolen J. S.
Published: December 2007

The objective of this work was to develop improved variations of the BEPS, FAC, and Sequential preconditioning methods used to solve composite grid linear systems. These methods are attractive since they use standard subgrid approximate factorizations in constructing the composite grid preconditioning. This paper describes two algebraic, multilevel grid coarsening procedures which allow efficient "black box" implementation of FAC and BEPS. The coarsening procedures are compared with regard to their effect upon convergence and computer efficiency. In addition all three methods may be modified to use variable step subgrid solutions to enhance convergence.
A Linear Equation Solver for Massively Parallel Computers
Authors: Li K-M. G.
Published: December 2007

The latest generation of parallel supercomputers promises to deliver computational performance that is orders of magnitude higher than that of the sequential supercomputers. The major obstacle to using these supercomputers for reservoir simulations is the lack of software. Most existing reservoir simulators were developed to run on sequential computers and must be restructured to take advantage of these parallel systems.

The major bottleneck in the parallelization of a reservoir simulator is the solution of the linearized finite difference equation. Currently, the most robust techniques for solving large scale reservoir simulation problems are preconditioned conjugate gradient like methods. However, the more robust preconditioners such as nested factorization and ILU factorization are not suitable for parallel computers.

This paper describes a parallel linear equation solver that is suitable for large and small scale parallel computers. It is based on the preconditioned generalized conjugate residual method. The new preconditioner is a parallel variant of nested factorization. For the problems tested, the new solver is as robust as the more traditional solvers for sequential computers. Results are presented for large scale reservoir models running on the Cray C—90 and a massively parallel CM-2.
Multigrid Methods for Petroleum Reservoir Simulation on SIMD Machines
Authors: Dendy J. E.
Published: December 2007

In this paper we consider several multigrid methods on SIMD (single instruction, multiple data) architectures. The advantages and disadvantages of these methods are discussed. Actual timing data will be presented only at the meeting, since otherwise this paper would contain data five months old, rendering it obsolete in the current fast-moving world of parallel computation.

In a previous paper [DMRRS], a semicoarsening multigrid procedure was considered for solving three-dimensional problems that arise from pressure equations in reservoir simulation. In this procedure, semicoarsening was coupled with plane relaxation in order to accommodate anisotropies and heterogeneities. Subsequent work by Schaffer [S,SW] has improved the robustness of this procedure. Results of the implementation on the CM-200 of the twodimensional version of this procedure will be described, as will progress on the implementation on the CM-5 of the two-dimensional and three-dimensional versions.

Another possibility involves the use of Mulder's method as developed by Naik and Van Rosendale. [NR] In this method semicoarsened grids in both x and y (and z in three dimensions) are employed. The advantage is that general anisotropic problems require only point relaxation. This approach is compared to the above approach and shown to have better convergence factors but to be less efficient than the above method on machines like the CRAY-YMP. This method is being implemented on the CM-200 and CM-5 by using concurrent relaxation, interpolation, and restriction. This approach yields great parallelism but at the sacrifice of the splendid convergence factors.

A third possibility involves standard coarsening multigrid. This method seems less attractive than semicoarsening multigrid for SIMD machines, especially for three-dimensional problems.

A final possibility is the method referred to as BHT in [DIR]. This method uses standard coarsening but for every grid employs four coarse grids, thus keeping all the processors busy at every level. Busyness of processors is not innately virtuous, but the employment of supplemental coarse grids gives rise to a method which requires only point relaxation for simple anisotropic problems. It is the latter feature which makes the BHT method potentially attractive.
Under and Over Relaxation Techniques for Accelerating Nonlinear Domain Decomposition Methods
Authors: Nacul E. C. , Lett G. S.
Published: December 2007

Large reservoirs usually consist of several distinct drainage regions. Moreover, for simulation it may be desirable to use different grids in some regions. Such cases motivate a domain decomposition strategy at the reservoir level. The problem is split into several subproblems, corresponding to different drainage regions or grid types (or whatever other physical reasons there may be that motivate such a splitting). The subproblems can be solved separately, and by exchanging boundary information, the error at the interfaces can be reduced iteratively.

Such algorithms are attractive for parallel computation because of their coarse granularity and less communication, as compared to domain decomposition methods within the linear solver. A straightforward implementation of such methods, however, may converge slowly. The reason is the nonlinearity of the problem and the fact that in case of a linear problem, such methods would reduce to a simple block-Gauss-Seidel method, which is not an efficient solver. It is essential to apply acceleration techniques for such domain decomposition methods.

We present here two dynamic acceleration techniques for nonlinear domain decomposition methods. They use information from the previous time step, to calculate relaxation parameters. To test the robustness and efficiency of these techniques, three-phase black-oil examples with significant flow across subdomain boundaries and examples using locally refined grid have been computed. Results for our approach are compared with standard linear solvers. They show that with suitable acceleration techniques, a domain decomposition on the nonlinear (physical, reservoir) level is a feasible way to obtain coarse-grain parallelism.