bluuebunny/crossref_metadata_2025_split huggingface dataset:
The First Through-Tubing Capillary String Installation in the UK Sector of the North Sea
Authors: Bremner B. , Murphy L. M. , Affinito R. J. , Larnach A. , Sanders D. L. , Taggart M. J. , Willis M. J. 
Published: July 2010

Abstract
The Britannia field has been on production for approximately 10 years. Produced fluids are retrograde gas condensate with some associated water. In recent years, as the reservoir pressure has declined, some of the wells have entered a region where flow has become unstable due to the phenomenon of liquid loading. In a small number of cases the effects of liquid loading are so pronounced that the wells remain largely shut in and are not considered to be part of the “production pool”. In others a cyclic clean up program is employed which involves routing the wells periodically through the test separator at low pressure to unload the associated liquids.
In 2007 a Low Rate Well Strategy was developed in order to identify possible solutions to address this issue of liquid loading. One such strategy was that of continuous foam injection at or just above the producing interval. This chemical application works by lowering the minimum liquid unloading rate of an individual well, thus enhancing the ability of that well to lift liquids from the wellbore.
The method selected by Britannia to enable continuous injection of the chemical foamer was via a permanently installed thru- tubing capillary string. Capillary tubing is similar in appearance to coiled tubing. However it is much smaller in size, the outer diameters ranging from 1/4” to 5/8” and is more akin to the control line used to contain fluid for the operation of sub surface safety valves.
The process by which a suitable chemical foamer for Britannia was selected and tested, both from an effectiveness and compatibility standpoint, will be discussed.
The first operation to install a 3/8” capillary string on a Britannia well was successfully completed in May 2009. This was followed by a second installation in July 2009. The procedure included the installation of a modified tubing bonnet, which allows chemical injection at the wellhead, and deployment of a capillary tubing system which contains an integral sub surface safety valve. This system provides a flow path for produced fluids, and allows continuous injection of the chemical foamer from surface to the producing interval, whilst maintaining full well integrity.
This paper will discuss the first installations of this system in the UK sector of the North Sea. The planning and design activities, followed by the offshore implementation, will be described in detail. Candidate selection and a review of well performance, both pre and post capillary string installation, will also be included.
Whilst the “Wellhead Modification System” has been employed for the initial installations, simplified designs are being reviewed for future Britannia wells and these will also be discussed.
Coiled-Tubing Fracturing: An Operational Review of a 43-Stage Barnett Shale Stimulation
Authors: Castañeda Juan Carlos , Castro Luis , Craig Steven , Moore Christopher , Myatt James 
Published: July 2010

Abstract
Traditional multi-stage high rate fracture treatments have been used in many shale and conventional formations. These treatments typically rely on composite bridge or frac plugs, run on wireline to provide zonal isolation. In a typical frac treatment, rates of up to 100 bpm are normally divided between four to six pre-perforated clusters per stage. Typical spacings between clusters are 50 to 100 ft. In theory, fluid would divide equally between each perforated cluster, however that is an unlikely scenario since stimulation treatments will follow the path of least resistance. To improve production results, targeted fracturing operations are gaining in popularity in many formations.
Some targeted operations utilize abrasive perforating via coiled tubing (CT), followed by the fracture treatment down the annulus. The treatment flush is modified to include an underdisplaced dense slurry stage to act as the isolation mechanism. In vertical wells, proppant settles by gravity covering the recently treated interval. In horizontal wells however, a plug enhancement additive (PEA) can be used to achieve isolation, partially mitigating gravity effects. Moreover, instead of splitting flow between four to six clusters, most horizontal treatments target only one discreet cluster/zone at a time. Significant gains in fracture control are obtained with this method. Initial targeted operations were applied to 300 ft of frac spacing, thus reducing the number of stages per well when compared to the 50 to 100 ft cluster spacing on higher rate frac operations.
This paper describes one targeted operation in a horizontal well where the spacing was reduced to 60 ft. In all, forty-three stages were successfully stimulated using enhanced sand plugs for zonal isolation.
Tapered-OD Connection using a Spoolable Connector
Authors: Ehtesham M. A. , Zhong A. , Domann R. E. 
Published: July 2010

Abstract
The coiled-tubing (CT) industry has evolved from using smaller pipes with lower-grade materials to bigger pipes and high- strength materials. However, the offshore installations and equipment still need to catch up with increased weight and handling demands. A tapered outer-diameter (TOD) string is one solution that provides the benefits of larger string while keeping size and weight at manageable levels. This paper presents a study and analysis of using a spoolable connector (SC) to join strings of two different outer diameters (ODs).
A TOD string requires an 8- or 10-ft long “transition section” so that the string can pass through specially retrofitted injectors. The transition section is milled, from one diameter size to another, using a cold-working process. This transition section needs to be welded to the two strings and requires a manual butt weld. As an alternative, a transitional spoolable connector is being developed and virtually tested using finite element analysis (FEA), thus eliminating the need for a specially milled, butt-welded transition section.
One challenge with TOD-connection systems is that they tend to fail at the butt-weld between transition and core end of string. A 10-ft long SC was designed to transfer this high-strain area away from the transition where it would be less detrimental to fatigue life. SCs for regular pipes have been designed and tested in variety of sizes from 1.5- to 2.875-in. OD CT. The test data provided a base to compare the performance of this new transitional connector. Results from a 2- to 1.75-in. tapered OD string are presented. One complete bending event of a 20-ft long assembly was simulated on a drum using FEA, and results were compared with actual and virtual test data from pipe with SC and a TOD string with transition section.
High-Risk Coiled-Tubing Intervention Results in Substantial Savings
Authors: Thom F. N. , Taggart M. J. , Murdoch J. D. , Ewing B. 
Published: July 2010

Abstract
Shell U.K. Limited Teal P1 subsea well was completed in July 1996 with a peak flow rate of 40,000 bopd. During the completion phase there were a number of problems and failed attempts in setting the production packer, which subsequently resulted in debris in the wellbore. To prevent this debris damaging the turret assembly in the FPSO, a debris barrier, consisting of a perforated tail pipe and a 3 ½” bridge plug, was installed in the production tubing 50 ft below the TRSSSV. Problems with the TRSSSV and the subsea tree valves resulted in a completion workover being scheduled. Prior to pulling the production tubing, the A-annulus was pressurised to 3500 psi to reduce the differential pressure across the tubing. At 2850 psi there was a sudden loss in pressure indicating a leak in the outer casing string. The workover was suspended and the well left in a safe condition. Planning for a full abandonment was then implemented.
Two abandonment options were possible: remove the debris barrier and abandon the well using coiled tubing, or drill a secondary well which would intercept the reservoir section of Teal P1 allowing it to be isolated. The coiled tubing option was only given a 30% chance of success, but due to the potentially large cost saving if successful, this became the primary option. The main hazard in the coiled tubing intervention would be removing the 3 ½” bridge plug from the debris barrier which had been in place for over 12 years. To address this a number of onshore trials were carried out to determine if the plug could be milled if fishing was not achievable.
After a total of 52 coiled tubing runs with a variety of customised BHA's, the requirements of the coiled tubing intervention were met allowing full abandonment of the reservoir. This paper discusses the well history, requirements of the coiled tubing intervention, the onshore trials and the offshore operation.
Snubbing Units Used Effectively in Well Control Recovery Efforts
Authors: Wehrenberg S. R. , Baxter O. 
Published: July 2010

Abstract
This paper will discuss the use and advantages of employing snubbing units during and after well control operations. The benefits of snubbing units compared to coiled tubing are widely known and generally accepted in the industry. During some well control operations the advantages a snubbing unit provides can positively impact the outcome of the well.
From its inception solely as a mechanism for handing tubulars during well control operations, snubbing has evolved into a highly versatile technology, offering myriad operational, economic and HSE benefits. To illustrate the versatility of new generation snubbing technology in a variety of well control situations, the authors will present case studies of a number of diverse applications.
The paper is intended to educate operators and service contractors alike by sharing experiences, lessons learned and demonstrating the effectiveness of snubbing units in a variety of hostile well control environments, including its use with gunk squeezes.
The Design and Application of Snubbing Units for an HP/HT Environment
Authors: Wehrenberg Steve 
Published: July 2010

AbstractTypically, in a high-pressure, high-temperature (HPHT) well, operators incorporate heavy workover and drilling fluids to provide a barrier to control the pressure. Often, the end result is formation damage, loss of un-recoverable fluids and appreciable increases in workover and completion costs. To help alleviate this and other problems in challenging environments, the use of snubbing units has come into vogue as a viable solution to the obstacles and resulting problems associated with drilling, workover and completion operations in an HPHT environment. The technology has evolved to the point that it can efficiently perform any function required of a conventional drilling rig. Recent experiences in the Haynesville and other un-conventional shale gas plays onshore the US have demonstrated the advantages of snubbing units in a variety of applications, including those involving hostile HPHT environments.This paper discusses the evolution, design and application of snubbing units for HPHT applications with particular emphasis on the pre-well planning involved. To illustrate the operational, economic and environmental advantages of snubbing technology compared to coiled tubing and other more conventional approaches, the authors will present operational data from a recent HPHT well, along with a discussion on the ideal scenarios where snubbing technology should be considered.Designed to provide insight for both operators and service companies, the paper will share experiences and lessons learned to demonstrate the effectiveness of snubbing units in an HPHT wellbore.
Phase Stability of Calcium Sulfate in the System NaCl/monoethylene glycol/water
Authors: Lu Haiping , Kan Amy T. , Zhang Ping , Yu Jie , Fan Chunfang , Tomson Mason B. 
Published: July 2010

Abstract
Calcium sulfate is one of the dominant scales in the oil field. At high temperatures, hemihydrate (CaSO4·0.5H2O) and anhydrite (CaSO4) are the predominant sulfate scales formed, while gypsum (CaSO4·H2O) scale may form at low temperature during offshore production with long tie-back particularly if hydrate inhibitors are used. The prediction and prevention of calcium sulfate scales require accurate knowledge of the solubility and phase behavior of the three major phases of calcium sulfates.
The phase behaviors of the different calcium sulfate phases are related to the supersaturation state, temperature, and fugacity of water. In this study, the effect of a common hydrate inhibitor, monoethylene glycol (MEG), on calcium sulfate solubility and phase behavior was investigated. Three approaches were taken to determine the kinetics of calcium sulfate phase transition at various temperatures, ionic strengths, and MEG concentrations: (1) Dissolution of gypsum as the starting material, (2) Dissolution of anhydrite as the starting material, (3) Precipitation of calcium sulfate by mixing calcium and sulfate containing solutions. The effect of scale inhibitors on phase transition was also evaluated. This study was run in NaCl/CaSO4/MEG/H2O solutions at 0–6 molal NaCl and 0–95 wt% MEG at 4–70°C. The calcium concentrations in liquid samples were analyzed by Inductively Coupled Plasma Atomic Emission Spectroscopy (ICP-AES) and EDTA (ethylenediamine tetraacetic acid) titration, and the morphology, phase composition and water content of solid samples were examined by Scanning Electron Microscopy (SEM), X-Ray Diffraction (XRD), and Thermogravimetric Analysis (TGA). Phase transition of gypsum to anhydrate was observed in the presence of high concentrations of NaCl and MEG, regardless of the experimental approach. The transition boundary of temperature and NaCl and MEG concentration can be estimated quantitatively from solubility and fugacity of water. The inhibition of hexamethylenediamine tera (Methylene Phosphonic acid) (HDTMP) was also tested by using precipitation method to investigate the precipitation kinetics of calcium sulfate.
A New Synthetic Polymer Provides Improved Drag Reduction in Coiled-Tubing Operations in North Louisiana
Authors: Fox K. B. , Bainum M. S. 
Published: July 2010

Abstract
A new friction reducer was tested in various fluids to measure its performance in both a small scale flow loop and a field- scale system. The friction reducer is a high molecular weight, synthetic polymer, which is compatible with many brines, including calcium chloride and calcium bromide, and is thermally stable. The friction pressure study utilized fresh water and several brines, including 7% KCl, 9.7 ppg NaCl and 11.4 ppg CaCl2. The fresh water systems were pumped through 1½ inch diameter coiled tubing and straight pipe. For the heavier brines, a small scale flow loop, consisting of ½ inch diameter coiled tubing and straight pipe was used. There was good correlation between the fresh water friction pressures measured in the small scale flow loop and full scale system for straight pipe. Drag reductions as high as 81% were achieved in the straight pipe, and as high as 69% in coiled tubing. The heavier brines generally required greater polymer loadings in order to achieve substantial drag reduction.
Field applications of the new polymer have been conducted in North Louisiana, in the Haynesville Shale. These treatments utilized 9.8 ppg produced brines, and were pumped through 17,000 feet of coiled tubing. The polymer was applied as a suspension in order to provide enhanced field mixing. The use of the new polymer produced significantly greater friction reduction than previous technology, and provided improved economics.
Capillary Trapping in Carbonate Rocks
Authors: Lamy Celine , Iglauer Stefan , Pentland Christopher H. , Blunt Martin J , Maitland Geoffrey 
Published: July 2010

Abstract
Carbonate reservoirs represent a possible geological storage option for carbon dioxide from anthropogenic sources. We conducted capillary trapping experiments on different carbonate rocks to assess their suitability for storage. We measured the trapped non-wetting phase saturation as a function of the initial non-wetting phase saturation and porosity. We used refined oil – with a density similar to that of supercritical CO2 – as the non-wetting phase and brine as the wetting phase. The experiments were performed at ambient temperature and slightly elevated pressures. Saturations were determined by mass and volume balance. We found that the trapped non-wetting phase saturation rises approximately linearly with initial saturation. The porosity was shown to have a significant effect on both initial saturation and residual saturation. The influence of effective stress was also investigated. It was shown that carbonates have significantly different stress behavior compared to sandstones. As the pressure of the non-wetting phase increases during primary drainage, the initial oil saturation increases to a maximum value and then decreases, as the fluid pressure affects the pore structure of the rock.
Accurate Fluid Interface Tracking of Interwell Tracer Flow by the Constrained Interpolation Profile Method
Authors: Goda T. , Sato K. 
Published: July 2010

Abstract
An accurate numerical technique to follow tracer movement between sink and source is an invaluable tool in evaluating reservoir formation from interwell tracer test data. Tracer flow in porous media is modeled by the convective-dispersive equation. In case of convection-dominance over dispersion, the interface between tracer slug and tracer-free fluid becomes sharp and most finite difference techniques tend to cause numerical diffusion or non-physical oscillation.
To overcome this difficulty, the constrained interpolation profile (CIP) method, a universal solver of hyperbolic equations, is employed for solving tracer flow problems in this study. In the CIP method, not only the tracer concentration but also its spatial gradients are simultaneously evaluated at each gridblock, so that more continuity conditions can be imposed to construct an interpolation function between neighboring gridblocks and the sharp interface can be tracked more accurately. The computation procedure is followed by a semi-Lagrangian scheme; the governing equations of both tracer concentration and its spatial gradients are decomposed into convective and non-convective phases. The convective phase is calculated by the CIP method, while the non-convective phase by the finite difference approximation.
For one-dimensional test problems, the numerical results using the CIP method are almost in complete agreement with the analytical solutions, which verifies the accuracy of the developed method. Also the verification of the developed method for two-dimensional computation is provided by comparing the numerical results with semi-analytical solutions obtained using the complex variable boundary element method. Furthermore, from the numerical results of various two-dimensional example problems, such as staggered/direct line drive pattern floodings and flows in heterogeneous permeability fields, the developed method is found to be of use for practical purposes.
Low-cost Monitoring of Inter-well Reservoir Communication Paths Through Correlations in Well Rate Fluctuations: Case Studies from Mature Fields in the North Sea
Authors: Heffer Kes , Greenhough John , Main Ian G , Zhang Xing , Hussein Assef Mohamad , Nasreldin Gaisoni , Koutsabeloulis Nick 
Published: July 2010

Abstract
A major key to rejuvenating mature oil and gas fields for improved recovery is the ability to characterize the reservoir between existing wells: currently practised methods for surveying inter-well properties are generally costly. A recent project has combined three technologies which utilize readily available fluid production histories to produce a process for identifying inter-well reservoir communications in producing oil or gas fields. Fluctuations in the well production and injection rate histories are analyzed in the context of coupled geomechanical-flow processes involving activated faults and fractures through (i) the Statistical Reservoir Model (SRM), (ii) conventional correlation analysis and a new technique for extracting rate diffusivity tensors, and (iii) coupled geomechechanical-flow modelling. These technologies have been applied to five oilfields located in the North Sea from the North Viking graben to the Central graben with the key results that (i) the general long-range nature of rate correlations is consistent with some dependence on hydro-mechanical changes near a critical point, and (ii) the patterns of orientational distributions of rate correlations from all five fields are consistent with induced shearing on faults or fractures as an inherent mechanism of reservoir communication. Identification of major reservoir pathways is of substantial advantage to efficiency in reservoir management, leading to benefit for practical issues of well placements and configurations, injectivities, productivities, sweep efficiencies, short-term and longer-term forecasting. In particular the techniques can be used in a time-lapse fashion in order to monitor changes in reservoir behaviour and provide real-time updating of reservoir models. Together, these techniques can directly assist rejuvenation of mature fields; additionally, albeit tentatively, the improved understanding of fundamental reservoir mechanisms can lead to better planning of ‘green’ fields.
Rapid Determination of MIC in Oil Production Facilities with a DNA-based Diagnostic Kit
Authors: Skovhus Torben Lund , Sørensen Ketil Bernt , Larsen Jan , Rasmussen Kim , Jensen Michael 
Published: July 2010

Abstract
The use of culture-based microbiological methods is slow and can only measure the few sulfate-reducing Bacteria (SRB) that can be cultivated. Faster and more accurate techniques for the diagnostics of microbiologically influenced corrosion (MIC) are therefore required.
This paper demonstrates the benefits of applying state-of-the-art molecular microbiology methods (MMM) to the identification and quantification of the microorganisms contributing to corrosion in oil production facilities. For quantification of troublesome microorganisms MMM can be applied directly to solid samples from the oil field without the need for culture media.
The corrosion mechanism was investigated in two different cases: (i) a piece of piping with high corrosion rates from the water outlet of a separator from the Halfdan oil field, and (ii) a similar piece of piping from the Dan oil field with much lower rates of corrosion. The chemical distribution of elements was analysed using X-ray diffraction and the levels of MIC causing microorganisms were determined with qPCR (a DNA-based quantification method).
The results showed that corrosion in the piping from Halfdan was caused by MIC. The results also showed that not only SRB were involved in the observed MIC. High numbers of sulfate-reducing prokaryotes (SRP) and methanogens were measured in material from the Halfdan separator with high corrosion rates. The methanogens were particular abundant close to the metal/scale interface. The data indicates that the high level of microorganisms in the Halfdan separator speeds up the corrosion process by efficiently consuming hydrogen released during dissolution of iron.
Finally, the paper discusses the strength of applying qPCR as a standardized, high-throughput routine monitoring tool for MIC diagnostics when developing more reliable integrity management programs in the future. This study has shown that the improved molecular microbiological approach to MIC is important when designing and testing remedial actions towards MIC in oil field systems.