bluuebunny/crossref_metadata_2025_split huggingface dataset:
Useful Techniques for Evaluating Facility Expansion Projects
Authors: Dunn M. D. , Seck K. A. 
Published: December 2007

Abstract
Facility expansion evaluations are often performed when reservoir capacity exceeds the design limits of the installed facilities. In most cases, these evaluations are multifaceted and involve several engineering and operations disciplines. The inter-relationships between reservoir performance, pressure drop, process capacities, and operational assurances are not easily resolved. Consequently, the assessment of all scenarios and the identification of the optimal facility modifications require a proper systems approach. Otherwise, the proposed re-configuration of the facilities can deliver much less value than predicted.
This paper discusses a methodology that can be used to properly structure a facility expansion evaluation. Included is a work breakdown structure of fourteen steps. The paper also outlines several techniques and models to describe reservoir performance, illustrate cost versus capacity, screen solutions, and select the optimal project(s) for implementation. One technique is the use of "step change plots" to illustrate expansion options in terms of cost vs. capacity. An analytical based reservoir model has been developed to represent reservoir flow as a function of surface pressures. A pipeline model has been developed to predict pressure drops of various infield pipelines. A facility process model is used to identify bottlenecks and estimate process flow rates under different facility configurations.
The application of the methodology and the prescribed techniques reinforce a systems perspective to the evaluation so that tradeoffs and alternatives can be considered within the context of the overall business objective. It allows the evaluation team to discover the optimal solution and to distinguish the negative impacts of a narrow set of criteria. This paper will benefit reservoir engineers, process engineers, facility engineers, and operations personnel who are faced with the difficult task of evaluating the value of a facility expansion.
Selection, Operation, and Evaluation of High Temperature Oil in Water Monitor for Two-Phase Extra Heavy Oil (Bitumen) Test Separator Service at Peace River
Authors: Geneau Micheal D. 
Published: December 2007

Abstract
Since 1986, Shell Canada has been using two-phase separators for well test application in bitumen production service. As bitumen (8 to 10 API) at Peace River has a density similar to that of produced water, depending on operating temperature, the use of three-phase test separators is not practical. In bitumen service, a three-phase separator requires either heating or cooling plus diluent to reduce the bitumen density so that classical gravity separation can be achieved.
With a two-phase system, a means is required to determine the amount of oil in the produced emulsion. This is often achieved by either obtaining a representative fluid sample from the separator and determining the water cut in the lab, or by an online instrument. The two-phase well test system operates at temperatures ranging from 80 to 200 °C at an operating pressure of 1500 kPa. The water cuts from the wells range from 10 to 90 percent with an average of 40 percent. Agar's OW-201 water-cut monitors, in conjunction with Coriolis mass flow meters, were selected for test separator systems at Peace River.
This paper describes the field tests performed to verify the Agar OW-201 meter operation for Peace River service, Shell's operating experience to date and the performance achieved during one year of operation.
Design and Implementation of a High Rate Acid Stimulation through a Subsea Intelligent Completion
Authors: Bellarby Jonathan E. , Denholm Allan , Grose Trevor , Norris Mark , Stewart Adrian 
Published: December 2007

Abstract
The Machar field is primarily a naturally fractured chalk reservoir; with the subsea wells requiring acid stimulations in order to be economic. This paper describes the design and implementation of an acid stimulation for a new intelligent well completion. The combination of a subsea development, a high rate boat based acid stimulation and a surface operated intelligent completion provided several challenges.
The stimulation challenges arose due to the long reservoir completion and the required use of flow control valves with small tubing within this section. This prevented the traditional use of ball diverters in order to effectively treat the whole reservoir interval. By using the isolation capabilities of the intelligent completion, several intervals were sequentially treated. Within each completion interval, limited entry perforating provided the method of diversion necessary to effectively treat each perforation. In order for this to be successful, the perforations had to be centralised and shot prior to running the completion. Limited entry perforating therefore required physical gun shoot tests and a pump test through the shot holes. The results and conclusions of these tests are included in this paper.
The completion challenges related to the stimulation included assurance of the integrity of the sensitive downhole electronics and hydraulics required to operate the downhole valves and sensors. This assurance was vital as, for the first time with an intelligent completion, the stimulation involved pumping concentrated hydrochloric acid down the well at rates of up to 50 bpm.
Implementation of the stimulation was achieved with the real time multizone downhole pressure and temperature data providing several fascinating opportunities to view downhole mechanisms. Of particular interest is the pressure transient impact of a stimulation on adjacent zones and the cooldown effect on partially trapped annuli. The analysis of this downhole data is presented.
Drilling Facility Design - "A Wells Up Approach"
Authors: Nichols John , Lawrie Kenny , Jenkins Paul , McGill John 
Published: December 2007

Abstract
There are a number of developments where new dry tree platform drilling rigs are specified. In some cases the geographical location, number of wells to be drilled and the ongoing life of field intervention requirements lead to the need for a permanent rig installation.
The majority of permanent offshore rig installations has in the main been confined to the N. Sea region. As a result there is a significant experience base related to how the rig interfaces with the production platform and the lessons learned from operations that can be used to ensure appropriate drilling facilities are designed.
Compared to the overall project or field development cost the initial capital cost of the rig is usually a relatively small proportion of the project. However, when the operational cost of drilling and maintaining the wells is included it can account for between 30 - 40% of the overall development costs. Therefore the actual operational efficiency of the rig will have a significant impact on the overall project economics.
During the initial stages of a project it is essential that the project requirements such as the regulatory requirements, well designs, platform interfaces and philosophies and the appropriate levels of mechanisation are understood. This allows a clear definition of the rig equipment selection and functionality to ensure the rig is not over or under rated in order to allow the drilling team to provide a rig that delivers the expected operational efficiency.
Valhall Field - Still on Plateau after 20 Years of Production
Authors: Barkved Olav , Heavey Pete , Kjelstadli Roar , Kleppan Tore , Kristiansen Tron Golder 
Published: December 2007

Abstract
The estimated recoverable reserves from the Valhall field at start of production in 1982 were 250 MMSTB. Now, after twenty years on primary depletion, a total of 500 MMSTB has been produced and additional 500 MMSTB remains to be produced of the original 2.6 BSTB in place. This corresponds to a recovery factor of 40%. Possibilities to increase ultimate recovery have been defined. These will require further insights into the detailed architecture of the field and improved understanding of the reservoir energy and displacement efficiency. Approximately 50% of the drive to date has been from rock compaction. The field is a North Sea Chalk field producing from Tor and Lower Hod Formations, porosity is exceeding 50% in places, some fractured permeability is present, but matrix permeability is generally low, less than 10 mD.
Application of new technology has been fundamental in bringing the field up to current performance. New completion techniques combined with dedicated draw down schedules has been established to reduce influx of the weak chalk formations and reduce well failures. Special well design for a compacting and subsiding environment has also been implemented. Drilling of the overburden has been a key challenge. This has been partly mitigated by detailed geological mapping of problem zones versus structure, lithology, overpressure and wellbore stability analysis, but has also resulted in replacing extended reach wells by the installation of new flank drilling and production facilities. The particular characteristics of the overburden and chalk also pose challenges for data acquisition. Coring technology & practices are very tightly controlled, as is selection of logging devices.
A water flood scheme has been approved based on a successful water flood pilot, but issues related to sweep efficiency, presence of fault and fracture zones and large variation in thickness need to be understood to capture it's full potential. The reservoir will also experience extra water induced compaction and increased subsidence. New logging technology has recently made it possible to define and characterize the fracture system, which combined with a range of surveillance techniques will be key in this work.
Seismic imaging has generally been a challenge at Valhall due to the presence of gas in the overburden. Use of 4C seismic technology has improved this. In addition, the 4D seismic response appears to be very sensitive to production-induced depletion, compaction of the reservoir and subsidence of the overburden and seafloor. Seismic techniques will be critical in future development. For a more detailed review of the first 10 years of Valhall, reference is made to the paper by Ali and Alcock [1].
Relative Permeabilities for Post-Waterflood Depressurisation
Authors: Goodfield Matthew , Goodyear Stephen G. 
Published: December 2007

Abstract
A series of four depressurisation experiments were performed as part of a joint industry project, using core from two North Sea fields. Cores were aged with live crude and following a waterflood were slowly depressurised. The produced fluids were measured, together with in-situ saturation profiles for gas, oil and water. The laboratory results indicated low critical gas saturations, which decrease for slow depressurisation experiments (closer to field rates). However, the ultimate gas saturations left in the cores at the end of the depressurisations was found to be as high as 40% and would represent a significant loss of IOR target if this value were directly applicable to the field. In a previously reported interpretation, this was explained by an unconventional gas relatively permeability function, in which very low gas relative permeabilities persisted to high gas saturations.
A key element of the interpretation of the experiments is the representation of the core outlet boundary condition. New methods have recently been developed for waterflood SCAL studies influenced by capillary end effects, which allow the observed saturation history to be used as the boundary condition, overcoming the limitations of the conventional zero capillary pressure boundary condition. Analysis of the depressurisation experiments shows that movement of gas in the core is dominated by capillary forces. The new methods for imposing an outlet boundary condition were extended to the depressurisation situation and Experiment 4 was reinterpreted. A significantly improved match to the production and saturation data was found, without invoking unconventional gas relative permeabilities. A range of simulations was performed to assess the uncertainty in the inferred gas relative permeability and to highlight that in future experiments uncertainty can be reduced by performing a post-depressurisation waterflood to help quantify gas mobility. The new relative permeabilities are expected to lead to significantly higher predictions of gas recovery at the field scale.
A Dynamic Optimisation Technique for Simulation of Multi-Zone Intelligent Well Systems in a Reservoir Development
Authors: Arashi Ajayi , Konopczynski Michael 
Published: December 2007

Abstract
Intelligent well technology provides an operator the capability to remotely control, monitor and manage multiple horizons in a given well. Application of the technology has provided significant value, through the ability to control multiple zones independently, reduce total number of wells, reduce future costly well intervention, accelerate production between zones to maintain a plateau for extended period of time.
Common reservoir simulation tools are not well suited to model the performance of wells with downhole flow control devices, and specifically have difficulty automatically optimising the configuration of intelligent well control valves in the time domain, to maximise objective functions such as discounted production or hydrocarbon reserves recovered.
This paper reviews the process and results of reservoir simulation and modelling of a multi-layer, compartmentalized clastic oil reservoir with strong aquifer drive, developed using intelligent well technology. The paper describes the process by which an optimisation technique was incorporated in the simulator, with the ability to model binary and multi-position downhole intelligent well [L1]Interval Control Valves (ICVs).
The optimisation technique described was used to simulate the performance of a multi-layered commingled reservoir developed with intelligent wells. The production forecasts quantify the benefit of multi-position interval control valves over base case conventional development scenarios. For the typical reservoir studied, intelligent well systems accelerate production and maintain a longer plateau period when compared to conventional completion techniques.
Gas Holdup Imaging Identifies Complex Gas-Liquid Flow Regimes and Introduces a New Velocity Measurement in a Long, Cased Hole, Horizontal, Production Well
Authors: Whittaker Andrew Colin , Eriksen Synnøve Hjelmeland 
Published: December 2007

Abstract
Gas holdup probes run in a producing horizontal well on the Norwegian continental shelf are used to identify downhole flow regimes and compute the velocity of gas in intermittent flow.
The observed flow regimes are compared with the predictions of a number of gas-liquid flow correlations. The theory and quality of velocity correlations are discussed.
Quantifying the Value of Technical Work, Examples of Production Geophysics on the Brage Field
Authors: Robson Adrian , Hersvik Karl Jonny , Sperre Thomas 
Published: December 2007

Abstract
The Norwegian North Sea Brage field came on production in Sept. 1993. The field is currently producing approx. 6000Sm3/d and is on decline from its plateau rate of 19400Sm3/d. Drilling new production infill wells has increased production and has shown to be an effective way of prolonging the life of the Field. Learning from past well results has helped to improve methods. The main difficulty in this process is to accurately evaluate the success of well results. Statistics have been used to show trends and give an indication when variations occur. A detailed evaluation of well planning and well results was undertaken to demonstrate the value of specific geological and geophysical methods. Two examples from the Barge field are presented where the value of improved geophysical methods were estimated.
Safely Improving Production Performance through Improved Sand Management
Authors: Selfridge F. , Munday M. , Kvernvold O. , Gordon B. 
Published: December 2007

Abstract
Many operators implement a conservative approach to sand management implementing a "Zero Sand Production" or "Maximum Sand Free Rate" Criteria. This is due to the potentially severe consequences associated with sand production i.e. erosion, and the fact that existing standards and guidelines /1/ do not provide sufficient practical advice on how to manage erosion issues during operations. These criteria generally put restrictions on the production rate (and revenue) to reduce sand production and decrease the risk of erosion leading to a loss of containment. These restrictions are in many cases unnecessary.
This paper describes the development of an alternative approach which improves the production and safety performance of fields that are capacity restrained due to sand problems. The development of the approach started with a project for Conoco 1996 - 2000 /2/ and was further refined on a pilot project for Statoil in 2001 /3/, where it received the Statoil prize for the most successful R&D project in 2001.
From an erosion perspective the amount of sand produced is only one of many factors that must be managed; equally important factors are sand particle velocity, impact angle and material grading. By gaining a better understanding of the specific erosion characteristics of a field through: well sand risk ranking, identification of erosion critical components and detailed erosion assessment including 3D computer modeling; a more sophisticated erosion management strategy can be implemented identifying specific asset operational criteria, erosion monitoring and inspection requirements.
Implementation of this erosion management approach has provided operators with enhanced production, reduced inspection and maintenance costs without compromising safety and environmental targets and increasing/enhancing business performance.
Toward Zero Environmental Impact of the Produced Water
Authors: Knudsen B. L. , Hjelsvold M. , Frost T. K. , Eiken M. B. , Grini P. G. , Willumsen C. F. , Torvik H. 
Published: December 2007

Abstract
Reduced environmental impact is the goal when choosing produced water treatment technologies. On the Norwegian sector the method used for quantifying this impact is the Environmental Impact Factor, EIF. This method is computerized in a tool that calculates the environmental impact from each of a number of chemical component groups that are present in produced water.
Re-injection of produced water is the preferred option, and mostly used when pressure support is required. This paper, however, describes new treatment technologies aimed at produced water being released to sea. The technologies are suitable for different produced water compositions. The components in the produced water that contribute to the environmental impact are mainly: aliphatic hydrocarbons, heavy aromatic compounds (PAH), alkylated phenols and man added production chemicals. At several Statoil operated fields the corrosion inhibitor and H2S scavenger are giving a significant contribution.
Several new technologies will be described. Statoil has had a leading role and actively participated in the development and qualification of most of these technologies. The results from this work will be presented. The technologies will include the CTour process, Epcon CFU, droplet coalescing technologies as well as new technologies to reduce discharge of production chemicals.
The main conclusion is that knowledge is needed about which compounds contribute to the environmental impact of produced water before deciding which technology to use.
Parallel Reservoir Simulation Utilizing PC-Clusters in Massive Reservoir Simulation Models
Authors: Habiballah W. A. , Hayder M. E. , Khan M. S. , Issa K. M. , Zahrani S. H. , Shaikh R. A. , Uwaiyedh A. H. , Tyraskis T. P. , Baddourah M. A. 
Published: December 2007

AbstractFor the last five years parallel reservoir simulation has enjoyed great interest at Saudi Aramco. Realism in modeling the fields in Arabia requires the use of massive simulation models. These massive models capture detailed geological heterogeneity at relatively fine resolution. In addition, some of these fields have been producing for the last 50 years and are expected to continue to produce for decades to come. Today, there are more than 20 massive simulation models ranging in size from 500,000 to 10 million cells and are routinely used in managing the Saudi fields. Models of this magnitude require sufficiently "massive" computational power in order to carry out simulation studies in efficient and reasonable time. Faced with the challenge of meeting computational requirements, we were motivated to find a cost effective computational platform. In this work, we report on our experience in investigating PC-Clusters for mega-cell reservoir simulation studies. Our investigation demonstrated that commodity off-the-shelf Xeon based PC-Clusters can deliver an exceptional performance at minimal investment in computing hardware and software. Up to 9.6 million cells model running for 50 years have been tested. Currently Saudi Aramco uses PC-Clusters for its simulation work at not more than 15% of the cost of traditional solutions using supercomputers.
Investigation of New Tool to Unload Liquids from Stripper-Gas Wells
Authors: Ali Ahsan J. , Scott Stuart L. , Fehn Brad 
Published: December 2007

AbstractLiquid loading in low production gas wells is a common problem faced in many producing regions around the world. The techniques available to remove liquids from the wellbore impose significant capital and operational costs. This study investigates a new method for unloading and restoring continuous production of low rate (stripper) gas wells. The performance of a patented vortex flow modifier tool was examined using a 125-ft vertical flow loop of 2-inch diameter clear PVC. The vortex device was found to alter the basic flow structure in the pipe resulting in improved liquid flow. The tool was observed to reduce tubing pressure loss by up to 17 precent and lower the minimum gas velocity required to lift liquids up the tubing string.