bluuebunny/crossref_metadata_2025_split huggingface dataset:
The Cost of Carbon Capture and Storage in the Perth Region
Authors: Allinson W. G. , Dunsmore R. E. , Neal P. R. , Ho M. T. 
Published: December 2007

Abstract
This paper describes and reports the results of analyses of the costs of CO2 capture and storage in south-west Western Australia. We analyse the costs of capturing approximately 25 million tonnes per year of CO2, and injecting it one of three storage sites-the Gage sandstone offshore of Perth, the Dongara depleted gas field, and the Neocomian sub-crop offshore of Geraldton.
Our central estimates are that the real cost to capture, transport and inject CO2 for a period of 25 years is between A$58 and A$63 per tonne of CO2 avoided in A$2005 terms depending on the location of the injection site.
We also analyse how sensitive our cost estimates are to changes in key assumptions. The sensitivity analyses show that the costs of CCS can vary significantly with different assumptions for key variables.
Stepping on Development of Small and Medium Size Oilfields through Horizontal Wells—The Way Ahead
Authors: Tewari R. D. , Malik M. , Naganathan S. 
Published: December 2007

Abstract
Maximization of recovery from anisotropic small and medium size oil fields is a daunting task for operators. Development strategies and concepts implemented in large fields generally are not appropriate for small and medium size fields. Inappropriate strategies and methodologies of exploitation affect the overall recoveries and economics of the project. This is further complicated in tight, viscous and sand incursion prone formations. This paper discusses about number of small fields located in Muglad basin wherein oil accumulation is found in multiple layers of late cretaceous deposits. The formations are heterogeneous, unconsolidated with higher viscosity and strong aquifer support. Some formations are tighter too. Field performance is marred by exponential rise of water cut due to adverse mobility and lifting through ESP. Production is affected due to poor influx in tighter formations through conventional wells. This behavior is limiting the producing life of existing wells, resulting into decline in production and causing significant bypassed and undrained oil.
Horizontal wells with state-of-art completion both in openhole and cased holed with suitable artificial lift techniques were considered as one of the IOR option for maximizing well productivity in these thinly bedded heavy oil field with objective for tapping the bypassed oil and delaying the water production while controlling the sand production.
This paper discusses about the challenges in planning and executing cycles of real time well site well placement, completion, perforation and artificial lift selection. Lessons learnt and results of the well placement along with cost/production analysis will be presented. Production results to date have been remarkable with productivity improvement factor varying 3-4 folds compared to vertical wells. The paper illustrates how integration of different disciplines with focused efforts led to successful well placement, sand and water management in heavy oil environment and also oil production from tight formations.
Study on High-Concentration Polymer Flooding To Further Enhance Oil Recovery
Authors: Fulin Yang , Demin Wang , Gang Wang , Xinguang Sui , Weijie Liu , Chunling Kan 
Published: December 2007

Abstract
Initially the field operator considered injection of high-concentration polymer to be high-risk and marginally economic. But the results of the core flood experiments show that an incremental recovery over water flooding of more than 20% OOIP (original oil in place) can be obtained by early time injection of high molecular weight, high concentration polymer solutions, and the earlier the better. The incremental recovery is comparable to surfactant flooding but at a lower cost.
A high concentration (concentration 1,500 ppm ~ 2,000 ppm, viscosity 400 mPa.S ~ 500 mPa.S) polymer flood pilot test has been started in May 2003. The pilot is located in the West Central area of Daqing Oil Field and consists of 9 injectors and 16 producers. Before high concentration polymer flooding, 0.247 pore volumes of low concentration (1,000 ppm, viscosity 44mPa.S~51 mPa.S) polymer solution had been injected and the water cut at the central area had reached its lowest point (65.5%). By the end of April 2006, the water cut at the central area was 78.9%. After injecting high concentration polymer solution, the rate of the water cut increase slowed down and then the water cut decreased from a maximum of 79.6% to a minimum of 73.1% (a decrease of 7.5%) again. The current recovery over that of water flooding at the central area is already 16.7% OOIP.According to numerical simulation, when the water cut reaches 98%, 19.8%~22.9% OOIP incremental recovery over that of water flooding will be attained.
6 dispersed wells located in the West Central area of Daqing Oil Field started to inject a higher concentration of polymer fluid also rein March and August, respectively. The 6 wells were first injected by low concentration polymer and then increased the concentration of the injected polymer solution from 1,000ppm to 1,300ppm. At present, good results have been obtained.
Another pilot is located in the northwest of Daqing Oil Field and consists of 39 injectors and 44 producers. The pilot increased the concentration of the injected polymer solution from 1,250ppm to 1,800 and the molecular weight of polymer from 25×106 to 35×106. According to numerical simulation, when the water cut reaches 98%, 19.4OOIP incremental recovery over that of water flooding will be attained.
The above results show that this technology can enhance oil recovery economically.
A Synergy of New Technologies Successfully Overcomes Openhole Horizontal Completion Problems in Malaysia
Authors: King Kim , Terwogt Jan H. , YeeChoy Chen , Azer Alfred 
Published: December 2007

Abstract
Sarawak Shell Bhd operates the Shallow Clastics field, which targets two shallow gas-bearing reservoirs, H1 and H2. An early appraisal well had been drilled deviated, and 9-5/8-in. casing was used. A commingled upper completion and a sand-face completion using large-OD expandable sand screens through both targets was used. Upon completion, the well was cleaned up through a temporary well clean-up and test facility. The purpose of the well was to test productivity and evaluate the integrity of the downhole sand-exclusion installation. Fines production, possibly due to the failure of the sand exclusion method, steadily increased to the extent that the well was deemed unproducible to the facilities.
Due to the high fines produced from this first well, a re-evaluation of the sand exclusion method was undertaken before development of the remaining field. The re-evaluation included more extensive core analysis and reviews of the types of sand-face completions suitable for development of the H1/H2 reservoirs. This evaluation enabled the operator and a service/engineering company to develop an innovative sand-exclusion method that combined several new technologies.
This paper discusses the evaluation and the four wells that have been completed to date with this new sand-exclusion method and the well configuration to address the completion needs. The field implementation of the design, key success factors and results will also be summarized.
Ultralow Invasion Drilling Fluids: A Practical Route to Reduced Wellbore Instability, Reduced Mud Losses, Wellbore Strengthening, and Improved Well Productivity
Authors: Reid P. , Santos H. 
Published: December 2007

Abstract
Reducing the invasion of drilling, completion and workover fluids to as low a level as possible will alleviate many problems of mechanically unstable formations, differential sticking and lost circulation. A properly formulated ultra-low invasion fluid (ULIF) will also reduce formation damage and thereby often increase well productivity. In addition, certain classes of ULIF will provide wellbore strengthening.
This paper describes the technology used to produce a class of ULIF and will review the benefits that limiting fluid and pressure invasion of fluid brings to rock integrity, drilling performance and well productivity. The ULIF additives described are biodegradable, environmentally acceptable and can be used in water based, oil based and synthetic based fluids. They are easy to add to any mud system and the ultra-low invasion properties of the fluids are measured and maintained in the field by using a simple sand bed invasion test.
The paper focuses mainly on case histories from several regions of the world where ULIFs have been used. In North, Central and South America alone, over 120 wells have used the ULIF additives in the past 3 years. The products have also been used in India, the Middle East, Europe, Africa and the Far East. Log data are presented that clearly demonstrate the ability of a ULIF to reduce wellbore instability and fluid invasion. Evidence of wellbore strengthening is also presented along with several cases where well productivity has been increased. In addition to showing the enhanced technical performance obtained with ULIFs, we also demonstrate the economic benefits of using these fluids.
The same technology used to formulate Ultra-low Invasion Drilling Fluids can also be used very successfully – sometimes with modification – in completion fluids, workover fluids and cementing operations to reduce or eliminate the same problems.
Evaluation of Acid Treatment Results for Water-Injector Wells in Saudi Arabia
Authors: Al-Harbi M. S. , Al-Dhafeeri A. M. , Al-Rufaie Y. A. , Mohammed S. K. 
Published: December 2007

Abstract
Several acid treatments were conducted in the Ghawar filed to increase the well injectivity and to support the reservoir pressure in this area. Vertical and horizontal wells with an open hole completion in a carbonate reservoir were selected to be a candidate for post acid treatments evaluation study. These wells were stimulated using hydrochloric and emulsified acid with foamed viscoelastic-based water. Viscoelastic-based water system was used to enhance the diversion mechanism and the lifting process for the spent acid following the treatment.
In this paper new correlations for acid treatment design were obtained from an extensive study of several case histories that can be used for optimizing future acid treatments design in the Ghawar field. This study was mainly utilized the results from the post acid treatment jobs in terms of HCl acid, emulsified acid and viscoelastic volume correlated with the well's injectivity. Based on the study results, there is a strong relationship between the emulsified acid volumes with the injectivity index for the selected wells.
Reservoir Crude-Oil Viscosity Estimation from Wireline NMR Measurements—Rajasthan, India
Authors: Zittel R. J. , Beliveau D. , O'Sullivan T. , Mohanty R. , Miles J. 
Published: December 2007

Abstract
In 2004, the Mangala, Aishwariya, and Bhagyam fields were discovered in Rajasthan, India. Oil viscosity is a main factor controlling performance from these high-permeability paraffinic reservoirs. PVT data show areal and vertical variations in crude properties. Meter-by-meter geochemical core data corroborates vertical variations in oil composition. Continuous wireline measurements of nuclear magnetic resonance (NMR) properties and station NMR properties from wells drilled with both water- based (WBM) and synthetic oil-based muds (OBM) were also used to calculate a viscosity profile. This paper correlates results from all techniques, and shows how NMR measurements can provide oil viscosity profiles in compositionally-complex pools.
Black oil PVT samples typically test several meters of reservoir, while Rajasthan geochemical data is available at meter-scale. NMR logs provide continuous data, and calibrated to PVT and geochemistry, can provide the most detailed picture of in situ viscosity variations.
Results were used to construct a detailed spatial description of the reservoir's in situ oil viscosity. The NMR data helped define a zone of biodegraded oil up to ~25 meters thick above the oil- water contact (OWC), and showed thin accumulations of higher- viscosity oil on top of minor shale layers within oil columns. The major conclusion is that detailed in situ oil viscosity profiles can be developed from conventional wireline T2 measurements.
Techniques presented allow quick and accurate calculation of oil viscosity profiles from wireline logs, and can reduce the need for time-consuming detailed geochemical measurements. Results directly impacted the static and dynamic modelling of the Rajasthan fields and proposed waterflood designs (different for each field). Procedures described are generally applicable to reservoirs with similar datasets. Finally, the wealth of data presented allows a detailed examination of the viability of several approaches advocated for estimating in situ oil viscosity from wireline NMR measurements.
Results of the World's First 4D Microgravity Surveillance of a Waterflood—Prudhoe Bay, Alaska
Authors: Brady J. L. , Hare J. L. , Ferguson J. F. , Seibert J. E. , Klopping F. J. , Chen T. , Niebauer T. 
Published: December 2007

Abstract
The world's first 4-D surface gravity surveillance of a waterflood has been implemented at Prudhoe Bay, Alaska. This monitoring technique is an essential component of the surveillance program for the Gas Cap Water Injection Project (GCWI). A major factor in the approval process for the waterflood was to show that we could economically monitor water movement where a very limited number of wells penetrated the waterflood area. The drilling of numerous surveilence wells to adequately monitor water movement would have been cost prohibitive. Field surveys now conclusively show that density changes associated with water replacing gas are being readily detected using high-resolution surface gravity measurements. The gravity methods used to monitor the waterflood include time-lapse (4-D) measurement of surver the reservoir followed by inversion of the 4-D signal for mass balance and flood front detection.
This paper will focus on field results of time-lapse surface gravity surveys. Differences in the gravity field over time reflect changes in the reservoir fluid densities. The inversion procedure was formulated and coded to allow for various constraints on model parameters such as density, total mass, and moment of inertia. The gravity survey was designed to permit the inversion for reservoir mass distribution with resolution on the order of hundreds of meters in the presence of uncorrelated noise of reasonable magnitude (12 µGal standard deviation).
Time differenced gravity survey results clearly show an increase in surface gravity that is a result of the injected water mass. Density-change maps deduced from measured gravity- change show that water movement is reasonably similar to the reservoir simulations and the water detected in observation wells. The overall ultimate gravity signal is predicted to increase to approximately 250 µGal ultimately resulting in accurate maps of the water movement.
Multi-Objective Decision Making: A Critical Analysis of the Applicability of Renewable Energy Technologies
Authors: Rudduck N. , Khurana A. , Congreve M. , Lourens J. 
Published: December 2007

Abstract
This paper provides a demonstration of the Multi-Objective Decision Making (MODM) technique to assist complex decision-making through a study of renewable energies currently available and their applicability for implementation by an Australian E&P Company Santos whose current gas operations are primarily located in Central Australia.
In the case of renewable energy technologies and their future commercialisation, it is important to note that for planning and decision-making, simple cost minimization is insufficient to fully describe their commercial potential. Thus, a technique such as MODM is required to consider all the decision parameters, some of them being unquantifiable, such as corporate reputation, in order to make unbiased and forward thinking decisions.
The paper outlines the MODM methodology for deciding between defined alternatives taking account of multiple decision criteria. By expressing the problem in a table the analyst can phrase the problem in a way that enables systematic handling of large amounts of information and conflicting points of view. By studying the company's own set of priorities (value structure) a list of the decision criteria was developed. By ranking the renewable energies against these decision criteria the most applicable technologies for Santos were found to be Photo Voltaic Cells, and Parabolic Dishes.
This study highlights how MODM can be easily modified to accommodate different types of alternatives as demonstrated by providing the flexibility to compare Geo Sequestration along with renewable energies. This comparison was relevant because the company's motivation in reviewing renewable energy was to investigate technologies with the potential to add value to the Cooper Basin business. Other key findings that surfaced during the analysis were: clear definition of project scope is critical and results are very dependant on the validity of input data not easily quantified. The result of not adequately defining the scope was that insufficient time was available to spend investigating the pitfalls and fully accounting for dependencies or bias. Most importantly, active involvement of the company personnel from a wide variety of functions relevant to the decision is critical.
The conclusions in this paper are based on the outcome of the analysis described herein undertaken as part of the research project and do not necessarily reflect the views of Santos.
Theory and Application of Buoyancy in Wells
Authors: Aadnoy B. S. , Kaarstad E. 
Published: December 2007

Abstract
The paper presents a generalized buoyancy model for application in wells, called the generalized law of Archemedes.
There exist confusion in the oil industry about buoyancy effects as related to the force-area method (also known as piston force) or the principle of Archimedes, the stability force in buckling and axial forces during well intervention operations. This paper will present a general model called the generalized law of Archimedes, which is valid for all cases.
The paper also presents examples of application to ordinary drilling operations, deviated wells and different fluid densities inside and outside the pipe. For well intervention scenarios, the effects of wellhead shut-in pressures on buoyancy are demonstrated. This simple model, not requiring use of a "stability force", can also analyze buckling.
Using the generalized law of Archimedes, a correct assessment of the real axial load of the pipe is obtained, a critical factor for tubular work in petroleum wells. The model is also significant as it is simple and can be applied to all well operations.
Extreme Multistage Fracturing Improves Vertical Coverage and Well Performance in the Lost Hills Field
Authors: Hejl K. A. , Madding A. M. , Morea M. F. , Glatz C. W. , Luna J. , Minner W. A. , Singh T. , Stanley G. R. 
Published: December 2007

Abstract
In an attempt to improve production response, fracturing designs in the Lost Hills field went from a standard 3 to 6 stage design to an extreme 15 to 18 stage design to stimulate approximately 1000' of net pay. The previous standard designs were becoming borderline economic and if development was to continue then either production response had to improve or costs had to be reduced. Previous emphasis was placed on reducing fracture treatment costs by pumping fewer stages and lower proppant volumes, but the cumulative production response decreased as a result. Previous tests using an increased number of fracture stages did not improve economics because of the increased fracturing costs and minimal production increases. When a new coiled tubing fracturing technique was implemented to perform multi-stage jobs at reduced costs and the stage count per well was increased, production response and economics improved. This paper will discuss the differences in job execution, analysis of vertical fracture coverage using surface and downhole tiltmeter data, and cumulative production response from the different designs tested. Both treatment and stage design with this fracturing technique are being further refined as performance and statistical analysis of previous design changes is completed.
Novel Cement Composition for Completion of Thermal Recovery (ISC) Wellbores
Authors: Suyan K. M. , Dasgupta D. , Garg S. P. , Jain V. K. 
Published: December 2007

Abstract
This paper presents a new process for development of a novel cementing composition to provide ductility and thermal stability to the cement sheath in thermal recovery wells subjected to high temperature cycling during ISC process. In this novel composition a carbon-containing natural mineral fiber and an aluminum silicate additive are introduced along with Portland cement to perform effectively in wellbores having conditions prone to stress-induced cement failure.
ONGC's heavy crude oil-fields in north Gujarat, India necessitate the inroduction of thermal recovery process for improving the oil recovery. However the durability of the cement sheath consisting of API Class G cement admixed with silica is endangering the success of EOR process. The developed composition with carbon-containing natural mineral fiber (graphite) and an aluminum silicate additive (metakaolin) because of its durability at high temperature thermal cycling (&lt;4500C) and compatibality with of Portland cement is an ideal composition for application in thermal recovery wells. The formulated thermally stable cement slurry with graphite and metakaolin has no significant effect on compressive strength and liquid permeability at high temperature thermal cycling (&lt;4500C), thereby making it suitable for placement against combustion zone.
The field evaluation of this cement system in ISC wells of Balol & Santhal fields of ONGC in Mehsana asset is under-way. The developed novel cement system will solve the problem of charging of the subsurface shallow layers because of cement sheath failured during the in-situ combustion process.
Determining Cutting Transport Parameter in a Horizontal Coiled Tubing Underbalanced Drilling Operation
Authors: Gunawan Indra , Rubiandini Rudi 
Published: December 2007

Abstract
Underbalanced drilling is a drilling method that designs the hydrodynamic pressure to be lower than the formation pressure. At this condition, the formation's fluid flows to the well and circulated to the surface. This will surely affect the fluids properties at the annulus.
Fluids physical properties at the annulus are not easy to determine. This is because of fluids physical properties depend on hydrodynamic pressure and fluids composition, while the hydrodynamic pressure also depending on fluids physical properties. The composition of annulus fluids also affected by the influx rate that depends on the hydrodynamic pressure. Therefore, everything is connected to each other, and that's make the cutting transport parameter calculation become complicated. To solve this problem, we must make iteration between pressure, fluids physical properties, and the influx rate until we can find the correct value.
In this study, underbalanced flow modeling uses foam, emulsion, oil base mud as drilling fluid system and aerated mud with three kinds of influx, oil, water, and gas. Combinations of drilling fluids and influxes make a various result in cutting transport parameter and hydrostatic pressure.
This paper discusses the determination of hydrodynamic pressure in a horizontal coiled tubing underbalanced drilling operation, the determination of mixture fluids physical properties, and the determination of cutting transport parameter. This paper also discusses the effect of few other factors, such as coiled tubing size, hole size, drilling fluids and influx fluids to cutting transport parameters.