bluuebunny/crossref_metadata_2025_split huggingface dataset:
Analysis of Carbon Capture and Storage Cost Supply Curves for the UK
Authors: Hare Phil 
Published: December 2007

Abstract
This paper reports modeling of economic supply curves of Carbon Capture and Storage over future time horizons and examines how the economics change as the volume of deployment increases – ie to develop a cost supply curve for all the major static emission sources on the UK mainland.
We consider the supply curves for both the sources and storage sinks as well as when combined by a transport network. For the composite curve, the market implications of the likely economics, the context of the EU ETS and other market considerations are considered.
A reasonable basecase suggests that up to 100mt pa of carbon dioxide could be stored at prices below £30/tonne before any carbon allowance income is included.
The author is grateful for support in developing this paper from Barry Ladbrook of Pöyry Energy Consulting, Ewa Kmietowicz, George Marsh and Jo Rowbotham of the DTI, Sam Holloway of the BGS and Isabelle McKenzie and Mark McKenzie of Equilibrium Consulting. The project was supported by the Department of Trade and Industry.
The Rhum Field a Successful HP/HT Gas Subsea Development (Case History)
Authors: Brown Alastair , Farrow Chris , Cowie Jim 
Published: December 2007

Abstract
The Rhum Field is a high pressure / high temperature gas accumulation in the North Viking Graben with an estimated GIIP volume of 1Tcf. The P198 licence was awarded to BP and the Iranian Oil Company (U.K.) Limited (50/50) in 1972 and is located approximately 380km north-east of Aberdeen in 115metre water depth. First gas was in December 2005 with production of 250 million cubic feet per day from 1 new development well and the re-completion of the 2000 appraisal well. The field produces via a sub sea tie-back scheme to the Bruce Field platform, 43 kilometres to the south.
Rhum was discovered in 1977 with well 3/29–2, which penetrated a thick gas bearing sequence of Upper Jurassic turbidites. This well was plugged and abandoned without testing, owing to the difficulty in testing high-pressure wells with the tools available at the time. Twenty-three years later, in 2000, appraisal well 3/29a-4 was drilled and extensively cored and logged. Finally, in 2004/5, the field was developed with 2 new wells as part of a project that has now brought the 27 year old discovery successfully into production.
Production is through natural depletion with minimum expected aquifer support. The Field Development Plan provides for the completion of three development wells, including re-completion of the 3/29a-4 well. The sub-sea wells are individually tied back to the Rhum sub-sea manifold and from there connected back to Bruce via a single 16", pipe-in-pipe insulated flow-line, which is trenched and backfilled. The Bruce Platform processes the Rhum gas for onward transportation to St Fergus via the Frigg pipeline.
The Rhum Project used many new technologies in an innovative way in order to overcome the harsh and challenging environment of a North Sea HP/PT subsea gas development.

Location
The Rhum Field, discovered in 1977, is located in the Northern North Sea, 380 km north east of Aberdeen and 43 km north of the Bruce platform. The field contains approximately 1 Tcf (GIIP) of high pressure (12,500 psi), high termperature (300 degrees Fahrenheit), dry gas, and is owned by BP (50%), the Operator and the Iranian Oil Company (IOC) UK (50%).
The Rhum field has an aerial extent of approximately 25 square kms and is located in Blocks 3/24b, 3/29a, 3/29b and 3/29d, Figure 1.
Land Transport Safety Management Practice of Crude Evacuation, Greater S1 Assets, PTT E&P
Authors: Dhitavara Vitaya 
Published: December 2007

Abstract
Following a disastrous year of road accidents in 1998, including a contractor fatality and several third party fatalities the Company has investigated alternative crude evacuation options. However the crude evacuation by road remains the optimum solution. To reduce the associated risks with road transport of crude to As Low As Reasonably Practicable (ALARP) the Company has employed a road transport consultant to study and implement the Land Transport Best Practice that could be sustained through the field life.
By implementing; a) road environment improvement, b) crude fleet improvement, c) public awareness campaign and engagement, and d) crude evacuation management, i.e. set up a defensive driving training center, journey management plan, driver reward programme the Potential Loss of Life (PLL) of 8% - 10% could be realized, compared to previous years PLL of 16% - 18%.
Leak Location in Subsea Umbilicals
Authors: Stebbings T. F. , Alexander P. D. , Evans K. D. , McEwan I. K. , Ryan N. J. , Marstrand J. , Riiser K. 
Published: December 2007

Abstract
Leaks in subsea umbilical systems are highly problematic as they are difficult to locate and the eventual egress of fluid may be a considerable distance from the actual line failure due to the presence of additional outer sheath(s).
However, in late 2006, by applying their knowledge of how leaks affect the pressure and flow characteristics in a pipeline, Brinker Technology developed an analytical tool which enables them to calculate the approximate location of a leak in a single line of an umbilical bundle. This technique was effectively put to use in November 2006 when, on behalf of Norsk Hydro, Brinker Technology were able to successfully calculate the location of a leak in an Ormen Lange main umbilical.
Further to an analytical leak location assessment Brinker can deploy their proven core product, Platelet Technology®, to seal the leak and add further assurance and a greater degree of accuracy to the location estimate.
Platelet Technology® involves the remote injection of discrete particles known as "Platelets®" into a pipeline which are carried to the leak site due to the flow. When they reach the vicinity of the leak fluid forces entrain them into the leak and hold them against the pipe wall thus facilitating sealing. By doping the Platelets® with a radioisotope prior to deployment an ROV mounted detection device can then be used in this region to pin-point the exact location of the entrained Platelets® and hence the leak.
Both these techniques, the analytical leak location tool and Platelet Technology®, will be presented in this paper with emphasis on the recent operation for Norsk Hydro.
The Equilibrium Free-Gas to Liquid Ratio (FGLR) Method
Authors: Cunningham Peter , Krijger Giel 
Published: December 2007

Abstract
The equilibrium free-gas: liquid ratio (FGLR) method is a new method for calculating gas production rates within a material balance model. The method calculates the reservoir FGLR at which there would be no overall movement of the gas-liquid contact. It is then assumed that the reservoir is tending towards such an equilibrium position i.e. the reservoir FGLR converges towards the equilibrium FGLR. Given an estimate of the rate of convergence and a forecast of liquid production (from decline analysis, for example), these assumptions are sufficient to give an approximate forecast of a reservoir or well gas production profile.
The method can be used to forecast associated gas production from oil-fields with significant gas-caps, especially thin oil-rims, for which wells are usually drilled close to the original gas-oil contact. It gives a gas production forecast broadly comparable to a decline-curve oil production forecast. Unlike the Muskat method, it does not depend on unmeasurable reservoir-scale relative permeabilities.
The method has been been mathematically derived from some basic assumptions about average reservoir behaviour. The validity of the assumptions and the method have been checked by comparison with historical production data from eight oil-rim reservoirs. The method has been successfully in use for reserves evaluation for a group of producing Nigerian oil-rim fields for the past four years. The evidence suggests that the method is a useful and robust approximation, but further validation would be very useful.
If further validation confirms its general validity, then the equilibrium free-gas:liquid ratio method would become a useful part of material balance theory and calculations for oil-fields with associated gas production.
Competence-Based Management for Recruitment, Deployment, and Commitment
Authors: McAllister Douglas 
Published: December 2007

Abstract
Competence is a much-used expression in the present business environment but surprisingly, it is a concept which is commonly misunderstood. In support of recruitment, competency based systems have been around for many years. Many businesses have used competency assurance systems, often driven by quality management systems, for some time. Internal staff assessment processes using competencies as their measurement system are also quite commonplace
Part of the difficulty many people have with competence assessment is that it tends to be something ‘done to them’. Individuals rarely see any personal advantage to having their competency assessed or any advantage to contributing to the assessment of others. It is often viewed as a necessary evil that the business needs, perhaps to sell into certain markets or to keep up with the competition. It can be seen as a business overhead, a non-value adding activity and worst of all perhaps, a paper chase.
When competence based systems are viewed in this way, organizations are simply not getting the value that such an approach can yield. Viewed as a paper chase, competence assurance is an overhead, a cost and, other than ‘ticking the box’ in your quality management system, does little for the efficiency of you business.
Estimation of Variable Fluids-Mixture Density With 4D NMR Logging
Authors: Minh Chanh Cao , Caroli Emmanuel , Sundararaman Padmanabhan 
Published: December 2007

Abstract
Whereas matrix density is known from core analysis or spectroscopy logging, so far no technique is available to estimate the apparent fluid density that the density log measures. In wells drilled with OBM, the near-wellbore fluids composition and distribution can be very complex. Yet, the current practice to compute density porosity is to use an ad hoc constant fluid density. This could lead to erroneous estimation of porosity. For example, in a 30 pu sandstone drilled with OBM, every 0.1 g/cm3 error in fluid density leads to 1.5 pu error in porosity.
Numerous studies of near-wellbore fluids with 3D NMR (T1, T2, D) maps from NMR logging tools have shown a very complex fluids mixture that can include water, oil, OBM, and condensate/gas. However, the map acquired at a single depth of investigation (DOI) might not represent the fluids mixture that the density tool measures.
The advent of radial fluid profiling with advanced magnetic resonance tools provides the needed fourth dimension—radial information that can be inverted jointly with conventional 3D NMR to unravel both fluids mixture and radial distribution. Because the near-wellbore NMR region closely matches the density region in both radial and axial directions, the two sets of data form "perfect" consonant volumes. Continuous 4D NMR maps are thus ideal to estimate the variable mixed fluids density. This value can be expressed as the double integration of all individual fluids detected by NMR weighted by the geometrical radial response function of the density log. The inner integration estimates the mixed fluids density. The outer integration computes it at 95% radial response of the density log.
Examples are shown in which variable fluid density confirms subtle fluid changes recorded by density-neutron logs in sandstone formations offshore West Africa. These sands have variations in grain size and shaliness that control permeability and therefore the OBM invasion. Another example shows large porosity deficits when the contrasting fluids density is large, such as gas invaded by OBM. In all cases, density porosity computed with the variable fluid density agrees with local field knowledge and other methods. A side benefit is the reconciliation of NMR and density porosity discrepancy, because density porosity is often the reference to which NMR logs are judged.
Use of Advanced Pressure Transient Analysis Techniques To Improve Drainage Area Calculations and Reservoir Characterisation: Field Case Studies
Authors: Du Kui-Fu 
Published: December 2007

Abstract
This paper presents several field examples of applying two independent methods of increasing tested area estimation and improving reservoir characterisation, based on utilising the entire well test history rather than just a single pressure build-up (PBU) or drawdown period. The two techniques are the pressure-rate deconvolution and the conventional pressure transient analysis (PTA) based "shrinking box" approach. A large number of the field cases are studied to illustrate their benefits as well as procedures for the minimum tested area calculations under various reservoir geometries. These field examples demonstrate that both methods, if carefully used, can yield almost identical radii of investigation derived from the entire test sequence and that the deconvolution technique can reveal additional reservoir information which may not be detected otherwise.
High-Performance Water-Based Insulating Packer Fluids
Authors: Ezzat A. M. , Miller J. J. , Ezell R. G. , Perez G. P. 
Published: December 2007

Abstract
Deepwater production well design and equipment installation presents a host of challenges for operators. One of the major problems is the uncontrolled heat transfer to outer annuli and heat loss from the production tubing which can be detrimental to the integrity of outer annuli. This can reduce the well productivity in case deposition of paraffin and asphaltenes occurs, and could contribute to the formation of gas hydrates. Vacuum insulated tubing (VIT) has had limited success but has numerous drawbacks (e.g., cost, breakdown, "hot spots" at connection joints, etc.). To avoid these problems, high viscosity insulating packer fluids (IPFs) have been employed to thermally isolate production tubing from the exterior pipe and to provide the required hydrostatic pressure.
Numerous combinations of both water- and oil-based materials have been utilized in attempts to devise a cost effective solution. Successful fluids have a low inherent thermal conductivity, remain viscosified or gelled to eliminate convective heat transfer and are expected to have service lifetimes of up to 20 years. However, the current state of the art falls short of meeting these objectives. Oil-based IPFs often have low thermal conductivity, but cannot be weighted, suffer from toxicity and often come with HSE issues. Water based IPFs can be weighted, but generally have temperature stability limitations &gt; 250°F (121.1°C) as well as higher inherent thermal conductivity than oil-based IPF's.
Through extensive investigation of multidisciplinary technologies, a superior performing aqueous-based IPF was developed for elevated temperatures. The novel system delivers performance beyond conventional systems of comparable thermal conductivity (k). The new system covers a density range of 8.5 - 14.6 lb/gal (1.02 – 1.75 sp.gr.) and displays heat transfer measurements between 0.12 - 0.17 BTU/hr ft°F. High-temperature static aging tests have demonstrated superior gel integrity with no phase separation or syneresis after exposure to 280°F (137.8°C) for three months. Parallel testing at 325°F (162.8°C) has shown similar success. The new fluids are hydrate inhibitive, pass oil and grease testing, and can be made environmentally acceptable for the Gulf of Mexico. Laboratory data generated under deepwater simulated conditions will be presented and discussed in this paper.
Cost-Effective Lateral-Junction Isolation in High-Pressure Air-Injector Wells
Authors: Asbill Steven , Webb Alan , Rogers Hank , Adkins Darrell 
Published: December 2007

Abstract
High-pressure air injection (HPAI) has proved to be a valuable improved oil recovery (IOR) process in fields where other recovery processes are uneconomical.
As in every upturn in the oil and gas industry, hydrocarbons in unconventional, tight, mature, and other challenging formations attract added interest when the economics appear to be positive. With more efficient technology to extract greater percentages of the reservoir, operating companies are re-entering old fields and successfully increasing production.
When exploiting existing wells, costs can be reduced by entering accessible main wellbores and sidetracking to new areas of the reservoir. In those fields where the production has naturally declined over the years, some type of injection program may be required. In certain situations, available injection resources and infrastructure will lead to a high-pressure air injection (HPAI) model. HPAI is an extremely corrosive and hostile environment, so ensuring proper well construction and isolation of the lateral junction is imperative. At the same time, the economics of these wells require a simple, cost-effective solution that is readily available for a high-volume field program.
This paper reviews solutions for these lateral-isolation instances and presents a simple, efficient and cost-effective system.
Technical Breakthrough in PCPs' Scaling Issue of ASP Flooding in Daqing Oil Field
Authors: Gang Cao , He Liu , Guochen Shi , Guoqing Wang , Zhongwen Xiu , Huaifeng Ren , Ying Zhang 
Published: December 2007

Abstract
The ASP flooding Pilot tests in Daqing Oilfield commenced in 1982. And since 2005, APS flooding has entered commercial application in several main oil companies. Although the recovery rate can be improved by 20% over that with water flooding, severe scaling in downhole equipment turned out to be the biggest issue for artificial lift systems in ASP producers. Sucker rod failure rate was extremely high for beam pumping wells. As for PCP system, its running life was relatively the longest one among all lifting methods, but it was still not economic. Severe scaling on the surface of pump and string was the major factor causing drastic oscillation of operating load.
Study indicated that surface energy of the material has great effect on scaling degree. Scale was easier to be formed on the materials with higher surface energy than that with lower surface energy. Using higher surface energy coating material was the main reason resulting in the severe scaling on traditional PCP rotors in ASP area. In that case, a novel ceramic coating technique was developed to decrease the coating material's surface energy to a much lower degree, and to prolong PCP wells’ running lives effectively.
Experiments showed that, elastomer's visco-elastic effect enhanced the periodic oscillation of PCPs’ operating load leading to high rod fatigue failure rate. In addition, interference fit design between rotor and stator also has certain influence on PCPs’ operation load. Based on the above studies, stator's surface modification technique and optimum interference fit design technique were developed to improve PCP's operation status. As an auxiliary treatment, a special chemical scale remover was developed to decrease the scaling degree of tubing and rod string.
These novel techniques have been applied in 58 PCP wells, the average running life increased from several months to more than one year. PCP systems’ operating status was improved effectively, and rod fatigue failure rate was decreased drastically.
Joint Industry Project: Improvised PPE Informatics Integrity Reducing Occupational Risks
Authors: Knight S. J. , Klinger Edward 
Published: December 2007

Abstract
This paper presents the background, approach and overview of the Phase 1 results of a five-phase Joint Industry Project proposal. Research commenced in 2006, to establish the need and methods to reduce Oil & Gas workforce exposure risks. The reports prepared throughout Phase 1 will become the shared property of the JIP participants. Not all details can therefore be disclosed within this paper. Presentation of the paper is intended to offer the opportunity to operators and organizations to be directly involved or associated in other ways with this initiative.
The advancement of technology in the area of PPE, integrated communications and emergency response systems will contribute to safety in petroleum industry areas such as; worker confidence in self and co-worker safety; remote vital signs health monitoring in conjunction with personnel tracking; non-reliance on human reaction and training for respiratory protection in toxic atmospheres; remote audio-visuals, relevant scenario data acquisition and optimized dissemination for effective emergency response.
The JIP is focused on bringing together all technologies within a single integrated solution. It will develop further the concept established during Phase 1, taking account of the established PPE performance standard criterion, to protect personnel while effectively and efficiently communicating reliable data for situational awareness. It is being shown that significant risk reduction benefits are achievable at all upstream E&P sites and facilities, whether in arctic or tropical locations and whether subject to technological hazards between construction and HPHT sour operations. Reducing the risk of incurring casualties during emergency response is a predicted achievable project objective.
Only by taking a green-field approach was it possible to identify the problems associated with existing PPE and communication methods so as to target a fully integrated solution that isn't currently available.
Quantifying Non-Darcy Effects on the Productivity of a Cased-Hole Frac Pack (CHFP) Well
Authors: Ouyang Liang-Biao 
Published: December 2007

Abstract
Well completion plays a critical role in the performance of a well in its entire life. More and more advanced well completion options are available for potential deployment in new wells, especially those in deep water and offshore; however, the cost could vary significantly from one completion type to the other. So could the well performance under a specific type of well completion.
There are many different completion options available in the industry, including open hole, slotted liner, inflow control devices, intelligent well completions (DIACS), perforated cemented liner, wire wrapped screen, ECPs, gravel pack, and frac pack, etc. Under most circumstances, the completion for a new well is selected based on its cost, performance, sand control potential, water shut-off possibility, reliability, and so on. An appropriate well completion design requires an accurate prediction of well performance.
Unfortunately, well performance prediction models available in current commercial packages need to be improved for certain well completion types to account for the details of fluid flow in the completion. One of the completions falling under this category is cased-hole fracpack completion where fluid flow would suffer because of the bottleneck effects associated with fluid flow in fractures and fluid flow along perforation tunnels. In particular, for high rate gas wells, non-Darcy flow would play a significant role for fluid flow along perforation tunnels, in fractures and formation, and thus would have substantial negative impacts on well productivity.
Appropriate quantification of the non-Darcy flow effects is critical for accurate well performance modeling for the cased-hole fracpack completion. In the present paper, the non-Darcy flow impacts will first be discussed for fluid flow in fractures, in formation, and along perforation tunnels. Methodologies to quantifying the impacts will then be discussed and the procedure to account for the effects in well performance modeling will be proposed. A series of sensitivity studies will then be conducted to illustrate the relative importance of key parameters on the non-Darcy flow. Finally, the new approach will be applied to a fictitious field to demonstrate what the difference in well productivity prediction would make with and without reasonable account for the non-Darcy flow effects.