bluuebunny/crossref_metadata_2025_split huggingface dataset:
An Innovative Back-up System for a 9-7/8-in. HP/HT Permanent Packer Provides a Solution for Damaged or Worn Casing in the North Sea
Authors: Robb Thomas , Valentine Ernie 
Published: July 2010

Abstract
Permanent packers are qualified by ISO 14310 V0 in a test fixture to meet the API 5CT internal casing dimensions; however, they do not account for any wear or damage in the casing. A test program was developed to test the packer at HP/HT well conditions and in worn casing. A major operator in the North Sea had been experiencing a problem with worn casing at the packer setting depth of an existing HP/HT well, causing a leak into the production annulus. A workover was required, and a calliper survey conducted after retrieving the tubing revealed two sizeable grooves along the longitudinal axis of the casing at 120° to each other.
This paper discusses the qualification and installation of an HP/HT permanent packer for worn casing. The test program consisted of the following:
Install the packer in 9-7/8-in casing and flow test to 3 bpm at 180°F to verify that the circulation around the packer did not damage the Aflas® element. Perform an application test using synthetic oil to mimic packer loading until failure, including setting, production, and hot/cold shut in.; apply 9,000 psi annulus pressure to support the casing during testing. In this case, the maximum temperature was 343°F or above for over 200 hours. Perform a modified ISO 14310 V0 test at 450°F with 15,000 psi differential pressure and 400,000 lbf tension and compression.
The packer passed all tests with no extrusion of the three-piece multi-durometer Aflas® element, and no leaks were detected at any of the load points in the application (liquid) test or modified ISO V0 gas test.
The discussion will include information on the packer design, HP/HT test in worn casing, and casing acceptance criteria. This test was the first packer test performed in worn casing that demonstrated the capability of the compliant back-up system to support a packer in worn casing and at HP/HT conditions.
Analysis on Scaling Substance of the E252 Heat Exchanger of Cracking Unit
Authors: Wei-wei Duan , Hong-fen Wen , Li-shu Wang 
Published: July 2010

Abstract
The paper analyzed the composition of the scaling substance of the E252 heat exchanger of 20 million tons cracking unit of Liaoyang petrochemical company with thermogravimetric analysis and ultraviolet fluorescence and atomic absorption spectrometry. We did the qualitative and quantitative determination on the scaling substance. We confirmed that the scaling substance was composed of the petroleum coke and sulfur element and iron element. There were 10.1% sulfur elements and 4.4% iron elements in the scaling substance. We found out the major reason that resulted in the scaling substance was the corrosion of the container by the sulfur compounds in the chemical material of the cracking unit.
3D Finite Element Modeling of Laboratory Hydraulic Fracture Experiments
Authors: Alqahtani Naif B. , Miskimins Jennifer L. 
Published: July 2010

Abstract
Laboratory experiments are an excellent way to visualize and improve our understanding of the hydraulic fracturing process. However, in order to truly apply the results of laboratory work to the field, an understanding of what artificial conditions are being created during the laboratory process must also be developed. This paper describes 3D finite element modeling and associated results using actual laboratory block tests as a basis. These models consisted of seven basic block systems, including a single layer system, with and without a wellbore, as a control case; a three-layer model with and without a wellbore; and a seven layer system, with a wellbore, without a wellbore, and with a cased wellbore. These seven systems were based on actual triaxial hydraulic fracturing experiments that were performed on mid-sized blocks (11 × 11 × 15 in) consisting of the same single, three, and seven-layers.
The fracture growth patterns in the actual laboratory tests were extremely complex, not at all like the planar fractures dictated by hydraulic fracturing theory. The intent of the modeling was to 1) determine the spatial stress contrasts being created by the material property contrasts of the layered systems in the triaxial system and 2) determine if the complex fracture growth could be accounted for by these modeled contrasts. Results were also used to determine the potential for shearing across the layered systems. A commercial, modeling software, capable of numerically determining the 3D stress distributions in the various porous media, was used. Numerical results were validated with analytical calculations.
The results of the modeling provide insight into the time-dependent application of stresses in a laboratory setting. It helped to explain the complex fracture growth in the actual experiments and gave some insight into the conditions that would cause vertical or horizontal fracture growth in a layered system of different material properties. The modeling also documented the creation of shear stresses which accounted for some fracture path deviation. The results of this paper aid in understanding the mechanisms of complex hydraulic fracture growth in reservoirs settings. Additionally, insight into the shear and tensile fracture mechanisms that generate acoustic events was gained.
Re-development of the Frøy Field: Selection of the Injection Water
Authors: Østvold T. , Mackay E. J. , McCartney R. A. , Davis I. , Aune E. 
Published: July 2010

Abstract
The Frøy Field, Norwegian North Sea, was closed down in March 2001 but there are plans to re-develop it. Previously, seawater (SW) injection caused persistent BaSO4 scaling problems in the production wells, so this study was undertaken to determine whether there would be any benefit in using Utsira formation water (UW; low SO4) as opposed to seawater as the injection water.
Thermodynamic calculations indicated that whether SW or UW is injected, the principle scaling risks are from BaSO4 and CaCO3 deposition. Being more difficult to treat, the study focused on the BaSO4 risk. ECLIPSE modelling was used to estimate FW:SW:UW ratios over time for each new well assuming (a) SW injection and (b) UW injection. The results indicated that in each case, initial peaks in BaSO4 Saturation Ratio (SRBaSO4) would occur after ~1.5–2.5 years before declining. The peaks reflect co-production of seawater already present in the reservoir and formation water. The subsequent decline in SRBaSO4 reflects (a) decrease in the FW:SW ratio (SW injection case) and (b) dilution of produced Ba and SO4 as the produced UW fraction increases (UW injection case).
An evaluation of produced water analyses from Frøy and from analogue fields indicated that reservoir reactions will occur at Frøy whether SW or UW are injected but significant BaSO4 would only occur in the presence of seawater. Two methods were used to quantify SRBaSO4 in the new production wells over time after accounting for BaSO4 precipitation in the reservoir. In the first, the amount of BaSO4 deposition in the reservoir was predicted from past produced water analyses and applied to the ECLIPSE results. The second involved the use of STARS to model the effect of reservoir reactions on the scaling potential. There were some differences in the results related to the amount of mixing predicted to be occurring in the reservoir, but contrary to initial expectations, both methods indicated that UW injection would not be beneficial.
Based on these results, seawater has been selected as the injection water resulting in significant OPEX and CAPEX cost savings.
Modelling Multiple-Contact Condensation of Heat-Transporting Fluids in Thermal Floods
Authors: Lawal Kazeem A. , Vesovic Velisa 
Published: July 2010

Abstract
Multiple-contact condensation (MCC) is proposed as an additional mechanism in the conventional heat-transport treatment based on conduction and convection. The conceptual model assumes that condensation occurs by multiple contacts between injected fluid and heavy oil, with the injectant condensing progressively as it traverses the reservoir, delivering latent heat along its path. The mathematical model entails coupling the energy conservation equation and temperature-dependent fluid-property functions. The resulting partial differential equation has been solved using finite difference Crank-Nicolson method. Simulation results are qualitatively consistent with available published experimental data.
Parametric studies have been performed, examining relative effects of some operational and petrophysical variables on the heating rates for viscous-oil formations. The results indicate that effect of formation permeability is highly non-linear, its impact being highest for highly permeable reservoirs. It has been shown that the initial reservoir temperature and the steam temperature both enhance the heating rate, while the drainage of oil and condensate has a detrimental effect.
The temperature profiles obtained in this work indicate that incorporating MCC mechanism into current conduction-convection models would eliminate the need for such models to use relatively high effective permeabilities to fit experimental data.
Laminar and Turbulent Friction Factors for Annular Flow of Drag-Reducing Polymer Solutions in Coiled-Tubing Operations
Authors: Ogugbue C. C. , Shah S. N. 
Published: July 2010

Abstract
The challenge of theoretical and numerical studies of annular fluid flow with varying eccentricity is mainly due to the required coordinate systems. Computational fluid dynamics (CFD) modeling provides the state-of-the-art approach of investigating fluid flow in such complex geometries. In this study, results from a series of numerical simulations for the fully developed laminar flow of non-Newtonian power law fluids in concentric and eccentric annular geometries are used to investigate the effect of eccentricity, flow behavior index, and diameter ratio (ratio of the outer diameter of the inner tubing to the inner diameter of the outer tubing) on axial friction pressure losses.
The friction pressure gradients predicted by the CFD simulations were verified by comparing with the published studies and flow data from a field scale experimental set-up. At a constant flow rate, it is confirmed that frictional pressure losses are decreased with increasing eccentricity. A good agreement was obtained with the Haciislamoglu et al. correlation, and the results of this study, especially at low values of eccentricity. At very high eccentricities, data from the CFD model yields lower friction pressure compared to Haciislamoglu et al. correlation. Haciislamoglu et al. type expression is obtained, incorporating the improved data of this study.
Next, this paper presents the results of an experimental study carried out to investigate friction pressure behavior of drag reducing polymer solutions, flowing turbulently through an eccentric annulus. The experimental set-up includes 30 ft of 3½-in. x 2 3/8-in., 200 ft of 3½-in. x 1¾-in., 69 ft of 5½-in. x 4-in., and 79 ft of 5-in. x 3½-in. fully eccentric annuli. Data analysis enabled the development of a new correlation using fluids apparent viscosity at 511 sec-1, generalized Reynolds number, and diameter ratio, all of which can be easily determined in the field, as independent variables. These new correlations for laminar and turbulent flow of drag reducing polymer solutions present an improvement to existing correlations, and also permit undemanding hydraulic program calculations for varying annular configurations.
The Use of Diutan Biopolymer in Coiled Tubing Drilling Mud Systems on the North Slope of Alaska
Authors: Sarber J. G. , Reynolds C. , Michel C. M. , Haag K. , Morris R. A. 
Published: July 2010

Abstract
Diutan biopolymer has recently been introduced for drilling with coiled tubing on the North Slope of Alaska.
Diutan biopolymer has replaced a xanthan biopolymer based mud system when drilling new sidetrack laterals from existing wells and also in well servicing with non-rig coiled tubing operations. This change in fluid systems was made by replacing the existing xanthan biopolymer used in the solids free mud system with a diutan biopolymer. The new diutan based solids free mud has shown improvements in several areas thus providing a significant performance advantage.
Coiled tubing drilling (CTD) has been conducted in Alaska since 1994 with over 600 sidetrack laterals drilled to date. For the majority of these wells a solids-free mud system was used to drill in either an overbalanced or managed- pressure drilling mode. The solids-free mud used was based on a xanthan biopolymer. In 2009 planning for more difficult well candidates suggested that the existing xanthan drilling fluid systems would be inadequate for drilling certain wells without exceeding acceptable working pressures in the coiled tubing or surface equipment. The higher pump pressures expected, along with acceptable coiled tubing design parameters associated with this higher pressure demonstrated the need to modify the drilling fluid. The standard solids-free mud was modified by replacing the xanthan biopolymer with diutan biopolymer. This new system demonstrated a 20% reduction in pump pressure, better hole cleaning, a higher tolerance to the pH changes related to cementing operations and longer fluid system life.
This paper will document the development of the diutan reservoir drilling fluid (RDF) system, including laboratory testing, field testing, a comparison to the xanthan based RDF, and the results of drilling actual wells. This new drilling fluid system has been in use now since July of 2009 and is the preferred drilling fluid used for coiled tubing drilling and well servicing in Alaska.
Improved Production Strategy for Enhancing the Immiscibile and Miscible CO2-Assisted Gravity Drainage Oil Recovery
Authors: Jadhawar P. S. , Sarma H. K. 
Published: July 2010

Abstract
Fundamental understanding and application of process parameters in numerical simulation that leads to optimized gravity drainage oil recovery at field scale is still a major challenge. Reservoir simulations studying the effects of well patterns and type of gas injection wells have not been reported so far. In first ever attempt, the mechanistic benefits of production strategy on gravity drainage oil recovery are identified in this paper. Effects of irregular and regular well patterns and vertical and horizontal gas injection wells are investigated using a fully compositional 3D reservoir model in both the secondary immiscible and miscible modes under the conditions of voidage balance, constant injection and production pressure and injection rates below the critical rate.
Regular well pattern provided longer oil production time at a constant rate until CO2 breakthrough compared to irregular well pattern. It then dropped almost vertically at the same cumulative oil recovery even at higher production rates. However, gravity drainage oil recovery was higher at higher rate combination after CO2 breakthrough. Results also suggested that the regular pattern could result in horizontal CO2 floodfront parallel to the horizontal producers, maintaining reservoir pressure, thus optimizing the oil recovery by additional 2.5% OOIP. Vertical injection and horizontal production wells in both the immiscible and miscible modes provided nearly identical cumulative gravity drainage oil recovery compared to the combination of horizontal injection and production wells in the regular well pattern. This suggests that the type of injection wells may not be a significant factor to impact the CO2-assisted gravity drainage mechanism. Results obtained herein would help in the optimization of CO2-assisted gravity drainage EOR process.
New Field in East Siberia: Challenges of Performing CT Operation on Vankor Field
Authors: Bochkarev V. , Vorostov A. , Smetanin S. , Sitdikov S. , von Hertzberg B. , Zagranichniy S. 
Published: July 2010

Abstract
The search for commercially viable oil reservoirs has led to expanding the frontiers of oilfield development. A new field in Russia known as Vankorskoe, which is 100 km north of the Arctic Circle in Siberia has been placed on production. This field is extremely isolated with winter access only by ice road and summer access by barge. The primary means of transportation is by helicopter.
Production from this field comes from producing zones at TVDs of 1680 m and 2780 m. Most of the wells are horizontal with a screen completion in the producing section.
Coiled tubing has been used in the Vankorskoe field since July 2008 to perform clean outs, kick offs, stiff wireline logging and hydrate removal operations. To date (Sept 23, 2009), 68 coiled tubing well interventions have been performed on 40 different wells.
The well profiles are designed with a reverse bend in it allowing the horizontal section of the wellbore to be directly beneath the wellhead. This profile has led to some challenges in reaching TD inside the 114 mm completion screen assemblies. Horizontal sections of up to 1000 m exist in these wells, which required the introduction of vibrator technology to this field. There is an 800 m thick layer of perma-frost which is coupled with extremely low reservoir temperatures.
This paper reviews the engineering, operational and logistical issues related to utilizing coiled tubing in a frontier field and the innovative solutions required to overcome these issues. It also discusses the expanded role that coil tubing will have as the field matures and production enhancements are required.
Cleaning Horizontal Wellbores Efficiently with Reverse Circulation Combining with Wiper Trip for Coiled-Tubing Annulus Fracturing Application
Authors: Li J. , Aitken B. , Jumawid F. , Alingig G. 
Published: July 2010

Abstract
Annular fracturing of multiple zones with coiled tubing (CT) has been practiced for more than a decade. A typical treatment involves sand jetting perforating, cleaning the well, fracturing and isolation. It is economically desirable to perforate, fracture and isolate each interval quickly, allowing all intervals to be treated in the shortest time possible. However, CT lying on the bottom of horizontal wells creates a solids bed during the perforation and fracturing stage, this introduces additional complexities into the reliable execution of the fracturing process. For tight formations, proppant beds have to be completely or partially removed, otherwise the pad can entrain the proppant which creates a high potential for premature screen out.
In this paper, a new approach to cleaning the hole between multiple annular fractures is proposed. This hole cleaning process involves circulating the clean fluid through the annulus to the bottom of the wellbore and bringing the sands back to the surface through the CT; at the same time the CT pulls out of the hole (POOH). The sand particles at the top section of the wellbore are swept toward to the end of CT, while the solids near the end of the bottom hole assembly (BHA) are sucked into the CT as it is pulled out of hole. Eventually, all solids are removed with the CT partially pulled through the initial bed section. As a wiper trip to surface is not required, the efficiency of this new process is higher than other cleaning processes. A full scale flow loop was used to simulate the process. Maximum POOH speed and the hole cleaning time were determined under various conditions. Empirical correlations were developed to allow for optimization of the process under the down hole conditions.
Silica-Templated Synthesis of Novel Zinc-DTPMP Nanoparticles, Their Transport in Carbonate and Sandstone Porous Media and Scale Inhibition
Authors: Zhang Ping , Kan Amy T. , Fan Chunfang , Work Sarah N. , Yu Jie , Lu Haiping , Al-Saiari Hamad A. , Tomson Mason B. 
Published: July 2010

Abstract
In this study, a silica templated synthesis route was adopted for fabrication of zinc-phosphonate nanoparticles to expand their use in the delivery of phosphonate inhibitors into formation core materials for scale control. Transition divalent metal Zn2+ was chosen due to its ability to significantly increase inhibitor retention and effectiveness. Zinc chloride was first adsorbed onto the surface of 22 nm silica particles, followed by gradual addition of diethylenetriaminepentakis (methylenephosphonic acid) (DTPMP) to form nanometer sized particles in the presence of sodium dodecylbenzene sulfonate (SDBS) surfactant. The physical and chemical properties of the synthesized Si-Zn-DTPMP nanoparticle slurry (nanofluid) have been carefully evaluated. The nanofluid was stable at 70°C in 1 % KCl at pH 6.7 for over 12 hours. The transport of the synthesized nanofluid through calcite and sandstone formation porous media has been investigated using column breakthrough experiments and modeled with a 1-D advection-dispersion equation. The nanofluid was transportable through these media and near total breakthrough could be obtained by pre-flushing the media with an anionic SDBS surfactant solution. The diafiltration experiment was designated to transform the nanoslurry into a less soluble phase, and such materials demonstrated a much longer inhibitor lifetime compared to the untreated ones. The long-term flow back performance of the fabricated nanofluid was examined via a laboratory squeeze simulation test where the nanoparticles gradually returned phosphonate inhibitors in the flow back brine solution, and the normalized return volume was comparable to conventional squeeze treatment.
Corrosion Management of Aging Assets from the New Operator's Perspective
Authors: Marsh Z. , Munday M. 
Published: July 2010

Abstract
Many assets in the UK sector of the North Sea are approaching or have passed the intended design life. The general decline for of many mature assets has been reversed as new operators invest significantly and target increased asset life when compared to the former owners. This poses a number of challenges for continued corrosion control. Some mature assets have seen multiple ownership transfers with repeat changes in corrosion management philosophies. For a mature asset historical records may be in various states of completeness. Operational conditions, likely to have changed radically since original design, may with investment be subject to increased requirements for gas lift, water injection and high water cuts. The new duty holder of a mature asset must take these factors into account when formulating their own corrosion management system. This publication examines the areas of concern to operators taking over ageing assets that are approaching or have exceeded design life. These include corrosion management, compatibility with increasing H2S levels (reservoir souring due to seawater breakthrough), corrosion mitigation, materials selection and fabric maintenance and repair. It discusses effective, but cost efficient methodologies that reflects the required future asset life.