bluuebunny/crossref_metadata_2025_split huggingface dataset:
PNG's Kutubu Project: Lessons in the First 100 Million Barrels
Authors: Magner T. N. , McKay W. I. 
Published: December 2007

Abstract
The Kutubu Project was approved for development in December 1990. Since that time twenty-four new development wells have been drilled, field facilities and export systems were successfully completed and commissioned, and some 85 million barrels of light, sweet Kutubu crude oil have been produced and exported (through July 1994). At present, the field produces approximately 120,000 BOPD from 27 vertical wells and two horizontal wells. Reservoir pressure maintenance is provided by gravity-stable re-injection of produced gas into 5 wells. By November 1994, cumulative production should be in excess of 100MMSTB.
In spite of all the of the studies and analyses conducted since the initial oil discovery in 1986, considerable uncertainty existed over the expected performance of the Kutubu reservoirs prior to initial production. On the whole, the reservoirs have met or exceeded expectations to date. This is in part due the effective planning and implementation of a strategy to manage the Kutubu reservoirs. This reservoir management strategy combines an aggressive program of reservoir surveillance, data collection, computer simulation and continuous reassessment of previous assumptions.
Alternatives to Proprietary Systems for Safety and Production Automation
Authors: Olszewski Keith , Godfrey C. W. , Perkins D. H. , Plunkett Joe 
Published: December 2007

ABSTRACT
In the prevailing economic climate of the oil and gas industry, operators must increase efforts to seek greater operational efficiency. They must also consider the more stringent regulatory requirements that are in place today for protection of personnel, equipment, and the environment. Implementation of a safety and production automation system for a producing field or battery can support both needs by optimizing production and reducing maintenance needs as well as facilitating compliance to safety requirements for personnel and the environment. If the installation embodies an "open system" philosophy, operational changes that may later require system redesign can be addressed more easily than with other proprietary systems and will involve lower maintenance costs.
Pressure Relieving System Design and Evaluation
Authors: Kenez J. D. 
Published: December 2007

ABSTRACT
The pressure relief system in a hydrocarbon processing plant is essential to its safe operation. In order to design pressure relief systems for a new plant or to evaluate existing systems, a systematic method should be employed taking into account the governing codes, industry recommended practices and the operating company's standards.
This paper describes a design procedure based on the preparation of a project specific overpressure design philosophy, which incorporates the designer's interpretation of the codes, recommended practices and standards.
All credible causes of equipment overpressure are then identified and required relieving rates quantified using simplified calculation methods and process simulation for fluid properties. The resultant information is stored in a data base and is then used to design the relief disposal system including relief valves, relief headers and knockout drums. Proprietary software is used for the sizing of relief system piping.
This design procedure, which can be equally well applied to the review of existing facilities, results in a sound plant relief design as well as providing auditable design documentation suitable for the maintenance of ongoing plant records.
Development and Trial of Microwave Techniques for Measurement of Multiphase Flow of Oil, Water and Gas
Authors: Ashton S. L. , Cutmore N. G. , Roach G. J. , Watt J. S. , Zastawny H. W. , McEwan A. J. 
Published: December 2007

ABSTRACT
A prototype microwave and gamma-ray MFM has been developed for measurement of oil, water and gas flowrates on production pipelines and has been successfully trialed at the Thevenard Island oil production facility. The microwave and gamma-ray MFM determined the oil and water flow rates with errors of 5.4 and 5.9% relative respectively for the wide range of wells and flow conditions during the trial period. A prototype non-intrusive microwave MFM is being developed for measurement of oil, water and gas flow rates on production pipelines. The microwave MFM will be trialed on the West Kingfish platform in Bass Strait in late 1994.
The Use of Blast Furnace Slag in North Sea Cementing Applications
Authors: Saasen Arild , Salmelid Bjarne , Blomberg Nils , Hansen Karsten , Young S. P. , Justnes Harald 
Published: December 2007

ABSTRACT
This paper discusses further the application of Blast Furnace Slag (BFS) in the cementing of oil and gas wells, with particular emphasis being placed on the suitability of BFS for offshore operations in the North Sea. The paper outlines the chemical reactions which occur during curing of BFS and discusses effects of different BFS sources and testing requirements. The application of BFS as a drilling fluid additive to improve cement bonding by solidification of the filter cake is discussed with respect to the effects of BFS on drilling fluid rheology and fluid loss. BFS is found suitable for low volume operations such as plug cementing, however wider use BFS is seen to be limited by logistics and occupational safety aspects for offshore North Sea applications. The environmental benefits to be gained by use of BFS is limited.
A New Correlation for Sedimentation of Concentrated Suspensions in Shear-Thinning Fluids
Authors: Allen Elise 
Published: December 2007

ABSTRACT
An experimental investigation has been made of the settling behaviour of concentrated suspensions in viscoelastic polymer solutions, as a function of the fluid rheological properties. The sedimentation experiments examined a wide range of shear-thinning and viscoelastic behaviour (power-law index n range 0.2 -1.0 and relaxation time X range 0.1 -100 sec), using model suspensions of closely-sized glass beads. The experimental results were compared with four available theoretical models which are based on the fluid rheological properties. A new relationship is proposed, based on the single particle settling velocity, a critical solids volume fraction c* and the fluid rheological properties. The new relationship predicts two different settling regimes: fast-setting for low solids loading c ≤ c*, and slow-settling for high solids loading c ≥ c*. The new relationship simplifies to the well- established Richardson-Zaki correlation for sedimentation in Newtonian fluids.
Biologically Controlled Water Diversion Demonstrated by New Visual Experimental Technique
Authors: Paulsen J. E. , Oppen Eirik , Vatland Arild , Hanssen J. E. 
Published: December 2007

ABSTRACT
A microbial enhanced oil recovery (MEOR) technology for optimisation of waterflood sweep efficiency was studied using a transparent pore micro model and a recently developed cybernetic image processing method (Automated Microscope Observation Reaction System = AMORS). Indigenous seawater microbes were stimulated with a nutrient package and allowed to develop inside the once through flow cell; a replica of the pore structure of a North Sea sandstone reservoir.
Microbial growth, as a result of subsequent controlled addition of nutrient and minerals, was observed in the automated microscope observation /reaction system. This novel integrated software/hardware cybernetic design allows approximated real-time, essentially simultaneous observation of several critical sites in the network and facilitates selective recording and compilation of observations as a function of the biological activity at each particular site. Local in-pore flow velocity measurement was possible to carry out by measuring the velocity of the particulate matter in pores/pore throats of different sizes. Sensitive, automated monitoring of the micro model pressure gave additional information of the degree of blockage.
Attachment of bacteria and development of bio mass, slime and extra cellular polymeric material was found to be most pronounced in channels of preferential water flow. The growth and subsequent narrowing of the pore network was not following a homogenous pattern, The possibility of predicting the blocking phenomenon as a function of growth rate of bacteria and/or concentration of nutrients (flow rate) is discussed with reference to the data collected with the AMORS system.
The use of micro models fitted with the AMORS package is an important step in revealing the nature of microbial blocking phenomena in porous matrices. Reservoir potential evaluation and consideration of MEOR process logistics, as compared to alternative treatment methods indicates that selective biological diversion may be a highly cost-effective and controllable way of optimising waterflood sweep efficiency in many North Sea reservoirs.
AMORS is a flexible tool recommended for investigating processes that take place on a micro/macro scale.
SAG Injection in a North Sea Stratified Reservoir: Flow Experiment and Simulation
Authors: Hanssen J. E. , Surguchev L. M. , Svorstøl Idar 
Published: December 2007

ABSTRACTThis paper is a study of a novel recovery process for stratified reservoirs with large permeability contrasts. A slug of foaming surfactant is injected alternately with gas, thus by analogy with WAG making this a SAG injection process. A combined ex-perimental and numerical evaluation demonstrating effective diversion by foam and significant recovery potential over WAG of the method is reported.An experiment with the new process was performed in a visual 2-D porous medium flow model approximately scaled to the conditions of a North Sea reservoir that is characterized by high permeability contrast and limited interlayer communication. The experiment showed poor performance of conventional WAG, which swept mainly the high-permeable layer. Placement of a surfactant slug and later foam generation in the swept layer was successfully demonstrated and gave efficient injectant diversion into the other layers, resulting in complete sweep of the reservoir model by continued WAG.History matching of the experiment was performed using a reservoir simulator in-corporating an empirical foam model and a reservoir description corresponding to the three layers of the physical model. Successful matching was obtained of WAG injection before and after foam treatment and the simulator captured the characteristic features of the foam process, including surfactant slug placement, foam generation, and injectant diversion. It was also found to allow some flexibility in process modelling by means of the available model parameters, primarily those for surfactant transport and loss, foam mobility reduction, and relative permeabilities.In summary the results of this paper show experimentally and by simulation on the same system that SAG injection as implemented here is superior to WAG injection and that the rich observations made in the experiment can be matched with reasonable accuracy using a commercial simulator with only empirical parameters.
Developing the North Morecambe Gas Field
Authors: Rosenberg R. H. , Lane D. J. 
Published: December 2007

ABSTRACT
The North Morecambe gas field due to be brought on stream in October this year is characterised by a shallow reservoir and a potentially corrosive gas composition. In the past developing such reserves would have involved extensive offshore facilities to allow drilling to achieve the required bottom hole locations and to process the gas for transportation to shore, including offshore separation and dehydration.
The paper discusses the advances in technology which allowed the development to proceed on the basis of a single not normally manned platform with all processing taldng place onshore.
It also covers the optimisation of the onshore processing facilities and the more interesting features of the pipelines and discusses the impact on the development, both onshore and offshore, of changes in environmental and safety legislation which have taken place in recent years.
The terminal is the largest gas reception facility in the UK, incorporating both carbon dioxide and nitrogen removal plants.
The project schedule was very demanding and this influenced the design both of the platform and the terminal. The challenges brought on by the constrained schedule and the solutions adopted are also dealt with in the paper.
Application of a Scale Inhibitor Squeeze Model to Improve Field Squeeze Treatment Design
Authors: Sorbie K. S. , Yuan MingDong , Jordan M. M. 
Published: December 2007

ABSTRACT
The most common remedy which is applied to solve mineral scaling problems in water producing North Sea fields is the scale inhibitor "squeeze" process. The central objective of this treatment is to maintain a sufficiently high level (typically, 2-50 ppm) of inhibitor in the produced water to prevent scale formation. The process is often applied in an empirical way although a body of knowledge now exists which allows us to design this process in a more rational engineering manner. This paper presents the results from an experimental and modelling study which aimed to improve downhole scale inhibitor squeeze treatment design by extending the squeeze lifetime in the Alwyn North field.
The model used in this work is a radial single well model for describing scale inhibitor squeeze processes in the near-well formation. In order to carry out the optimisation of the squeeze design, scale inhibitor laboratory core floods were carried out at reservoir conditions in order to derive inhibitor dynamic adsorption isotherms. The model then used the isotherms to perform the prediction of the lifetimes of the multiple scale inhibitor squeeze treatments and to optimise the squeeze operational design. The improved design was then implemented in the Alwyn North field and extended squeeze lifetimes have been achieved in broad agreement with predictions.
The model correctly reproduces the effect of (i) the residual inhibitor left in the formation from the previous squeeze treatment on the lifetime of the subsequent treatment and (ii) the effect of the operational parameters, such as overflush volume, on the squeeze lifetime. Using the first squeeze treatment in the well as the base case, a modified squeeze design (in this case, a larger overflush volume) was recommended based on the model prediction. This recommended design for the inhibitor treatments was implemented in the field by the operator and significantly improved squeeze lifetimes have been achieved.
The approach for squeeze optimisation described in this paper is referred to as the development of a "Field Squeeze Strategy". This, in contrast to the "rule of thumb" empirical approach, offers a systematic and quantitative method to evaluate and improve a scale inhibitor downhole squeeze treatment. In addition, this paper also addresses the issue of how fast the formation, where it is cooled by the injected squeeze fluids, would be warmed up during a well shut-in. We intend our findings on this matter to clear up some misconceptions on local formation cooling.
Low-Pressure Gas Field Operations in Leman
Authors: Dyck W. C. , Moore R. M. 
Published: December 2007

ABSTRACT
Shell U.K. Exploration and Production, operator in the U.K. sector of the Southern North Sea on behalf of Shell and Esso, has developed Block 49/26 of the Leman field, located at the southern end of the Sole Pit Basin. Gas production from Leman commenced in 1968, built to plateau level by 1971 and began declining in 1982. The field produces under natural depletion and reservoir pressure has declined from 3022 psia to 300 psia in central areas of the field. Maintaining field revenue above operating expenditure is the key to maximising recovery. The challenge of accessing the economic reserves from Leman has been tackled by maximising deliverability from the existing low rate producers, minimising operating expenditure and pursuing opportunities for productive infill drilling.
The capacity of existing wells is optimised by maximising drawdown on the reservoir. This is achieved through ongoing facility rationalisation and the tailoring of operating practices to manage the phenomena of liquid hold up and salt deposition associated with operating at low pressures. Novel completion technology has been developed to optimise the lifting of liquids from wells.
The planned rationalisation of the field's compression facilities and the conversion of six of the seven production platforms to not normally manned status will reduce operating expenditure by a third and ensure retention of high sales gas availability. In order to reduce the installations operational visit frequency, novel completion technology has been developed to provide downhole control of proppant back-production which currently occurs from some fracture stimulated wells.
The successful performance of a horizontal well in a poorly drained area of the field has opened the way for infill drilling opportunities and possible development of the low relief flank areas of the field. Future appraisal and development drilling requirements will be better defined following full interpretation of the recently acquired 3-D seismic survey.
Fully Coupled Analysis of Reservoir Compaction and Subsidence
Authors: Gutierrez Marte , Hansteen Harald 
Published: December 2007

ABSTRACT
This paper discusses the differences between fully-coupled and uncoupled formulations of models of production and subsidence. For highly compacting hydrocarbon reservoirs, production can cause com-paction of the reservoir and subsidence of the over-burden, and in turn, compaction and subsidence can affect the productivity of the reservoir by increasing the reservoir pressure (i.e., the so-called compaction drive). Intuitively, analyses of production and subsidence should be done in a fully-coupled fashion. However, most, if not all, of the analyses done so far on compacting reservoirs are uncoupled where production and subsidence are calculated in a staggered manner.
The results of the numerical analyses using an uncoupled reservoir simulation, and a fully-coupled finite element simulation based on Biot's formulation (both coupled and uncoupled simulations are based on single phase fluid) of a typical compacting reservoir are presented and compared. Different pore pressure response were obtained depending on whether an uncoupled or a fully-coupled analysis was performed, and also depending on whether there is arching of the overburden or not. The results of fully-coupled analyses of compaction and subsidence showed that the generation of additional pore pressure due to compaction cannot be correctly analyzed by simply adjusting the rock compressibilities in reservoir simulation. The most pronounced effect of coupling, obtained from the numerical simulations, is on the possibility of pore pressure increase close to the reservoir flanks even during production. The implications of the differences in the results of fully-coupled and uncoupled simulations are discussed.
A Mathematical Model of Microbial Enhanced Oil Recovery (MEOR) Method for Mixed Type Rock
Authors: Sitnikov A. A. , Eremin N. A. , Ibattulin R. R. 
Published: December 2007

Abstract1
This paper deals with the microbial enhanced oil recovery method. It covers: Mechanism of microbial influence on the reservoir was analysed;The main groups of metabolites affected by the hydrodynamic characteristics of the reservoir were determined;The criterions of use of microbial influence method on the reservoir are defined.
The mathematical model of microbial influence on the reservoir was made on this basis. The injection of molasse water solution with Clostridium bacteries into the mixed type of rock was used in this model. And the results of calculations were compared with experimental data.
Record Horizontal Wells for Deep Gas Reservoir Improve Productivity and Recovery
Authors: Graute Johannes , Eide Egil , Wenninger Guenther 
Published: December 2007

ABSTRACT
In 1993 BEB drilled two of the world’s deepest horizontal gas wells in the Zechstein and Rotliegend formations in northern Germany. The aim of the drilling projects was to increase profitability by achieving high production rates. By minimizing the number of production wells and usage of cluster locations, a reduction of field investment and operating costs should be attained.
To achieve the objectives, the projects were planned in a multidisciplinary team. Based on reservoir descriptions, derived from 3D seismic various sensitivity runs were performed. The aim of the runs being to assess vertical permeability distribution and horizontal hole length. The application of advanced drilling and completion techniques resulted in an optimized well design from an economic point of view.
Results of both wells proved that horizontal drilling into these deep reservoirs is technically feasible and economically attractive. A comparison of vertical drilling with horizontal drilling results in a 2 to 3 fold increase in the initial producktion rates with only a 1.3 to 1.4 times cost increase. Because of the promising results of the horizontal drilling programme in 1993 a further seven new deep horizontal and two re-entry wells were drilled in 1994. In future, BEB’s standard well design will be horizontal.