bluuebunny/crossref_metadata_2025_split huggingface dataset:
Low Scaling Potential Horizontal Wells and Scale Inhibitor Treatment Strategy
Authors: Raju K. U. , Lynn J. D. , Al-Nasser W. N. , Ayub M. , Hsu J. 
Published: December 2007

Abstract
Oil wells producing from carbonate formations generally experience chemical scaling (carbonates and/or sulfates) during some phase of their production history. In several Saudi Aramco vertical wells, production of formation water containing associated carbon dioxide gas has resulted in calcium carbonate scaling. Scaling potential studies have indicated the threshold level of an organic phosphonate scale inhibitor used to mitigate such scaling in these wells is less than one ppm. This low protection threshold allows considerable leeway in scale squeeze design for the problem wells. Phosphonate based scale inhibitor squeeze treatments provide the most common and effective means of preventing the scale formation in such fields. In vertical well applications, long squeeze lives of more than ten years have been observed in fields producing from carbonates. The residual inhibitor levels have fallen below 0.1 ppm in several of these wells without return of scale.
The increased drilling of horizontal holes and inevitable increases in watercut in these wells have led to scale problems. The design of a viable and economic horizontal well scale squeeze treatment was called for. Considerable problems are, however, inherent in the development of such horizontal treatment strategies. Sorbie, et al., recently published a mathematical scale inhibitor squeeze model for use in horizontal well treatments. This model was used to evaluate several treatment options for horizontal wells having a low carbonate scaling potential. Simulated residual returns and squeeze life data were used for different stages and scenarios in Sorbie's model to arrive at the most optimistic squeeze strategy. Based on the information provided by the model and previous vertical well experience, a simple and inexpensive bullheaded squeeze resulted in a successful treatment. This resulted in a substantial economic savings over a coiled-tubing delivered treatment. The theory behind this simple strategy will be discussed. The results of two case studies will be presented.
A Case Study of Boron Crosslinked Fracturing Fluid in Ultra-Deep Wall
Authors: Yongjun Lu , Yandong Chen , Zhongyang Zhao , Zhenduo Wang 
Published: December 2007

Abstract
The ultra-deep well has a number of characteristics such as high pipeline frictional resistance, high pump pressure in operation, single method for feed flow, high requirements on properties of fracturing fluid and proppant, difficult operation and high cost and investment risk. Fracturing fluid holds the technical key to fracturing operation of a ultra-deep well. As for the characteristics of the ultra-deep, high-temperature, low-permeability and water-injection well in Tarim's DH oilfields, this paper is focused on the properties of fracturing fluid, optimum selection of the additive for organic boron crosslinked hydroxypropyl guar gel (HPG) fracturing fluid and its formulation system including thickener, crosslinker, gel breaker, cleanup additive, fluid loss additive and clay stabilizer, which are suitable for the ultra-deep well in Tarim, presentation on application of fracturing fluid for the high-temperature deep well in Tarim, and analysis and discussion of a number of features of fracturing fluid, such as controlled delayed crosslingking, reduction of frictional resistance, optimization of formula, improvement of rheological property and low damage. The field application indicates that the organic boron crosslinked fracturing fluid is possessed of low frictional resistance, good rheological property, strong sand-carrying capacity, high gel breaking ability and low damage, satisfying the requirements on the fracturing operation for the wells with a depth exceeding 5850 meters.
Stress Corrosion Cracking: AISI 420, 4140, and 1045 on Alloy Steel Used in the Oil, Gas, and Geothermal Industry at Elevated Temperatures in a Hydrogen Sulfide Environment
Authors: Rubiandini R.S. Rudi , Subiatmono P. , Buntoro Aris , Supriyatman Deden 
Published: December 2007

Abstract
Stress Corrosion Cracking (SCC) is the intergranular or transgranular cracking on alloy steel as a result of combination between static stress and special condition. This type of corrosion is usually seen in geothermal, oil, and gas fields, which also produces hydrogen sulfide (H2S) as impurity. At present this problem can not be controlled successfully. To solve this problem, a laboratory study is conducted to determine the rate of corrosion by using three specimens of alloy steel, i.e. AISI 420, AISI 4140, and AISI 1045 which each of it will be simulated in hydrogen sulfide environment with varying pressures and temperatures. Based on the result of the laboratory test, AISI 420 with 13% Cr content is better than the others to solve corrosion problem in geothermal, oil, and gas industry, but the type of stress corrosion cracking for high strength steel (AISI 420) may cause cracking.
Study of Vertical Drilling Technology In High Dip and Application of BHA with Offset Axes Sub
Authors: Su Yinao , Wang Zhenying 
Published: December 2007

Abstract
Straight and fast drilling, especially in high-dip structure, is one of the key technology for deep or superdeep hole drilling, which is a "bottleneck" problem for the deep hole drilling. Based on analysis of its current situation, this paper presents the following technical factors which affect deviation and rate of penetration (ROP): side force on bit, tilted angle of bit and formation deflection force and weight on bit (WOB). The mechanism of hole deviation control, namely the proper treatment of relationship between side force of bit and formation force, is discussed with the affecting factors and calculating method for the treatment. PF plot method, a new method that is utilized to evaluate effects of deviation control and ROP is also brought forward. In this paper, structural characteristics and control mechanism of a state-of-the-art BHA with an offset axes sub (short in OSAS-BHA) designed by the authors are expounded, and its effectiveness shown in Shengke-1, Wei 2-31 wells in Jiangsu Province and Jingshi 1 well in east Sichuan Province is shown in detail. Field application indicated that the OSAS BHA could effectively control hole inclination, and at the same time remarkably increase the ROP in vertical drilling in high dip formations.
P. 145
Delayed Polymer Crosslinking Technique Used for Profile Control in Deep Fractured Reservoir with Low -Permeability
Authors: Wang Zhongmao , Dong Bo , Jiang Yingze 
Published: December 2007

Abstract
The delayed polymer crosslinking technique is used for profile control in deep fractured reservoirs with low permeability. Its mechanism, formulation and injection process have been researched for reservoirs with low permeability, low porosity, heterogeneity and both natural and artificial fractures. The weak gel has a dual function for both profile control and polymer flooding. It is an effective method for improving the flooding efficiency of fractured reservoirs with low permeability and low yield.
P. 169
Condensate Gas Phase Behavior and Development
Authors: Fang Yisheng , Li Baozhu , Hu Yongle , Sun Zhidao , Zhu Yuxin 
Published: December 2007

Abstract
In this paper condensate gas and its main phase behavior, as well as the gas condensate field development characteristics and schemes in China are introduced. Most condensate gas reservoirs discovered in recent years in China are rich condensate gas and some with light oil ring or bottom oil, so their developments are more difficult. Because of commercial demand for gas, usually the blowdown was used in this type of reservoir. In recent years, there are gas cycling field pilots in both Tarim basin and Dagang area in China.
The retrograde condensation and revaporization characteristics during depletion process of condensate gas reservoirs with or without oil ring; displacement oil efficiency using the energy in condensate gas cap and the pilots effects of gas cycling are discussed in this paper. Finally, it is suggested that condensate oil should be produced first and then natural gas using gas cycling under the condition of lacking of both long distance gas pipeline system and downstream installation, which will bring better effects in the development of condensate gas reservoir.
P. 439
Modeling Nonlinear Interactions among Near-Well Flow Restrictions in Well Deliverability Prediction and Simulation
Authors: Hwang M. K. 
Published: December 2007

Abstract
This work describes simulation of well productivity reduction due to near-well flow restrictions. The flow restrictions considered include: mechanical skin, partial completion, altered formation due to residual completion fluid or liquid dropout, and non-Darcy flow effects. It addresses two specific issues. The first is how to predict changes in well performance induced by changes in near-well parameters, as needed in history matching and well test analysis. A subset of this issue is how to estimate the impact of using well parameters to simplify simulation models such as partial completion skin and non-Darcy flow skin, instead of using more layers and solving the non-Darcy flow equation. The second issue is how to accurately preserve well productivity in a large grid block, as in the case of well productivity reduced by liquid dropout in a gas condensate reservoir model. To resolve these issues, this work uses direct simulation and heuristic total skin equations developed for 1D and 2D multi-layered cases with cross flow. The equation correctly represents the effects of nonlinear interactions among near-well flow restrictions on well productivity, resulting in an effective total skin that is much larger than the conventional linear sum of individual skin components. Numerical examples show the total skin equation can be used to predict well performance and to accurately preserve well productivity in a field-scale gas condensate reservoir model. The latter use of the equation shows a feedback mechanism, wherein the total skin is used to adjust the coarse-grid well productivity.
Response Surface Methods for Upscaling Heterogeneous Geologic Models
Authors: Narayanan K. , White C. D. , Lake L. W. , Willis B. J. 
Published: December 2007

Abstract
Experimental design and response surface methods provide a framework for evaluating sensitivities and estimating uncertainties in key reservoir responses.1 In this study, the approach is extended to model upscaled properties such as pseudorelative permeability. Pseudofunctions usually require fine grid simulations for every different reservoir description.2 Response surfaces can be used to generate pseudofunctions for different reservoir descriptions without expensive fine grid simulations. The response surface technique is simpler and cheaper than fine grid simulations and is more reasonable than using the same pseudofunction for different scenarios. This paper applied the response surface approach to waterflooding studies for models based on outcrop exposures of the Frewens Sandstone in central Wyoming.3 The study quantified the effects of different parameters of the reservoir model on the recovery responses and upscaled properties.
Scale-Up of Relative Permeabilities of Isolated Gridblocks Accounting for Boundary Effects
Authors: Suzuki Koichi , Hewett Thomas A. 
Published: December 2007

Abstract
This paper presents a new method for scaling up multi-phase flow properties which properly accounts for boundary conditions on the upscaled cell. Scale-up works by allowing us to omit the simulation of a complete finely-gridded model, but requires us to either make assumptions about the proper boundary conditions for the isolated blocks being scaled up or to determine them in some other way. To date, all scale up methods have made assumptions about fine-scale boundary conditions.
The paper describes how to use the concept of injection tubes (which are hypothetical streamtubes connecting the injection wellbore to all of the inlet-face fine gridblocks of the isolated blocks being scaled up) to determine the appropriate boundary conditions. The use of injection tubes enables us to capture the fine-scale flow behavior of a finely-gridded model at the inlet face of the isolated blocks as if the complete finely-gridded model was simulated. We describe how to scale up a whole finely-gridded model sequentially using injection tubes to determine the boundary conditions for two-phase flow.
This new scale-up method is able to capture almost exactly the fine-scale two-phase flow behavior, such as saturation distributions, inside each isolated coarse-grid domain. Further, the resultant scaled-up relative permeabilities almost perfectly reproduced the average performance of the finely-gridded model. To date, we have confirmed that the method is applicable not only to viscous dominated flow but also to flow affected by gravity for reasonable viscous to gravity ratios.
Scale Up in the Near-Well Region
Authors: Durlofsky L. J. , Milliken W. J. , Bernath A. 
Published: December 2007

Abstract
Scale up techniques are commonly used to coarsen detailed geological models to the scales more appropriate for reservoir simulation. These techniques typically generate upscaled permeabilities through the solution of the local pressure equation subject to some type of linear boundary condition. In the near-well region, coarse scale permeabilities computed in this manner may not adequately capture key features of the fine scale flow. In this paper, we present a general method for computing accurate coarse scale well block transmissibilities and well indexes for vertical wells in two and three dimensions. The method is based on the solution of local well-driven flow problems subject to generic boundary conditions. Simulation results for two dimensional systems indicate that the near-well treatment always provides improved predictions relative to those obtained using standard methods. In some parameter ranges, this improvement is quite substantial. Several three dimensional models are also considered and improvement relative to the standard approach is achieved in all cases. Extension of the method to accommodate complex well configurations could result in significantly improved coarse scale simulations of nonconventional wells.
Predicting the Potential Impact of Synthetic-Based Muds with the Use of Biodegradation Studies
Authors: Candler John E. , Stephen P. Rabke , Leuterman Arthur J.J. 
Published: December 2007

Abstract
The use of synthetic-based muds (SBMs) can improve drilling performance and reduce the volume of pollution generated by offshore drilling operations. Investigations into the environmental impact of SBMs to date have concentrated on the seafloor. The biodegradation rate of an SBM is an important factor in determining the overall environmental performance. Laboratory biodegradation tests are an inexpensive alternative to conducting field studies. However, most of the tests have been designed for water-soluble compounds and reproducible results are difficult to obtain with regularity for hydrophobic materials like SBMs. For this study, a variety of base fluids were tested using the SOAEFD (Scottish Office of Agriculture, Environment and Fisheries Department) solid-phase test. This paper will evaluate SOAEFD solid-phase test results against other biodegradation protocols using a set of criteria designed to identify the best biodegradation test for SBMs.
MABOPP – New Diagnostics and Procedures for Deep Water Well Control
Authors: James John P. , Rezmer-Cooper Iain M. , Sørskår Sverre Kr. 
Published: December 2007

Abstract
The long choke lines extending from the sub-sea blowout preventer (BOP) complicate the procedural difficulties in removing gas as a result of a well control incident. One of the traditional indicators of the ability to circulate out a kick has been the Maximum Allowable Annular Surface Pressure (MAASP). The high choke line friction losses when circulating and gas swap-out in the choke line(s) mean that the use of a constant MAASP (usually based on the last leak-off test) is inappropriate. The use of a dynamic MAASP that can be modeled using a simulator has been suggested as one possible indicator that can allow for the complex interactions between the high frictional losses, gas swap-out, kick tolerance, riser margin and reduced fracture gradients. However, the large fluctuations in this parameter during the kill make its interpretation difficult.
With the advent of instrumented BOP' s, many of the inherent complexities of the kill circulation can be avoided by the use of a new diagnostic: the Maximum Allowable BOP Pressure (MABOPP). Although this is still a dynamic quantity (as it changes during the kill), it avoids the large fluctuations of MAASP as it is isolated from the hydraulic and hydrostatic changes in the vertical choke line(s), and can thus be interpreted more easily. We illustrate the advantages of using MABOPP for deep water well control.
The interpretation of MAASP and MABOPP both involve estimation of the difference between two curves; this is not easy if they are both are changing. We introduce a second diagnostic to alleviate this problem: the ‘Fracture Margin’. This parameter dynamically tracks the difference in the curves and is a direct indicator of the safety pressure available at the last casing shoe.
The temperature effects in deepwater are highlighted and we propose the concept of Hydrostatic Imbalance to quantify the difference in hydrostatic pressure between the drill pipe and annular mud columns.
We also propose a technique of slowing the pumps, while maintaining a constant pump pressure, that is a safe and effective way to minimize the borehole pressure should the choke become fully open during a kill.
Casing Running Tool
Authors: Kamphorst G H. , van Wechem G. L. , Boom W. , Böttger D. , Koch K. 
Published: December 2007

Abstract
During casing running, risks of accidents with the stabber, the stabbing board and around well centre are still existing. In order to reduce the risks of accidents and to streamline the process a new Casing Running Tool is developed.
The basic idea of this device is that the Top Drive is used as a torque wrench and that several functions are integrated. A flush mounted spider is used. Integrated in this device are fill up and circulating functions, the power tong function, the top stabbing function and the casing hoisting function. The risk for accidents will be significantly reduced. The driller's operation is simplified and the casing running time is reduced. The Casing Running Tool incorporates additional features, such as the possibility of pushing and rotating the casing string while circulating. The reduction of casing running time, personnel, and risk of accidents create value and HSE benefits.
A first prototype is being developed. Design constraints that can be recognised at this stage of the development of the tool are mainly related to mechanized connection making. Both a theoretical and experimental approach are taken in order to define the design constraints.
In the development of the Casing Running Tool a step by step approach is chosen. All subsystems are designed as add-on equipment.
The Casing Running Tool paves the way to a complete automation of the drilling process.
Formation Evaluation in Ultra deep Wells
Authors: Henkes Ian J. , Prater Terry E. 
Published: December 2007

Abstract
Deep-water oil and gas exploration in the Gulf of Mexico has recently been the focus of much attention owing to the untapped potential of such a vast area. Of particular interest is the Garden Banks area, where sedimentary structures have been mapped using surface and borehole seismic techniques to depths greater than 30,000 ft. Formation evaluation at depths approaching 30,000 ft has necessitated the development of new technologies in the areas of tool conveyance and high pressure/temperature limitations. These new technologies have been put to the test in the logging of the deepest well ever drilled in the Gulf of Mexico, Garden Banks 386 #1. This well, located in 2663 ft of water, was drilled to a depth of 27,864 ft.
The Operating Company worked closely with the Service Company to prepare for the logging operation months in advance. The resultant technology and equipment included: Array induction, sonic, and integrated lithology and porosity tools rated to 500 °F and 25,000 psi for wireline formation evaluation.Extra strength logging cables in excess of 36,000 ft for tool conveyance.Surface mounted Wireline Dual Drum Capstan for surface tension reduction.The TLC* (Tough Logging Conditions) drillpipe/wireline conveyance system used in conjunction with wireline fluid sampling tools to sample the formation fluids downhole.
Utilizing these technologies resulted in the successful evaluation of the well. These new techniques and equipment will ensure proper evaluation of the continually increasing number of ultra deep wells.
Pressure Investigation Accomplished With Hydraulic Snubbing and Pressure Control Concentric Tubular String
Authors: Goodman Charles E. , Baker Robert V. , Smith Mike , Denton Kelly R. 
Published: December 2007

Abstract
Re-entry of a temporarily abandoned offshore well offered a unique well control challenge. When the 7-in. liner and 6-in. open-hole section had been drilled, well control problems had left the liner cement bond with questionable integrity. The well was ultimately circulated with kill weight fluid and a 100-ft surface cement plug was installed in the 9 ⅝-in. casing. A temporary abandonment (TA) cap was placed in the 9 ⅝ in. and the 13 ⅜-in. mudline hanger equipment. The 30-in. conductor pipe was severed 9 ½ ft above the mud line.
Two years later, subsurface investigation indicated that bubbles were escaping from the wellbore. The danger was that reservoir pressure was migrating under the surface TA caps. The authors were members of the pressure control team called in to solve the problem.
In planning for re-entry, the team designed a means of pressure investigation that relied on hydraulic snubbing equipment and well control expertise. The 13 ⅜-in. casing, with a burst rating of 3,450 psi, was the limiting factor to pressure control in a situation where 7,500 psi surface pressure was possible. The plan included installing a platform over the well, using a jackup rig, tying back the 30-in. conductor, removing the vented 13 ⅜-in. TA cap, and tying it to the platform. The team designed an elaborate surface blowout preventer (BOP) stack that included dual 8-in. overboard diverters and a pressure-confining tubing string which latched mechanically to the 9 ⅝-in. TA cap. Because it would be necessary to vent or bleed the potential well pressure to zero or use other means to kill the well for conventional re-entry, the team also designed a pressure investigation tool. A 150 K series hydraulic snubbing unit with 1 ¼-in. CS Hydril tubing would convey the tool to depth, where it would check surface pressure under the 9 ⅝-in. TA cap.
Drilling Fluid Considerations for Gulf of Mexico Depth Record
Authors: Prater Terry , Gleason Dan , Henn William E. 
Published: December 2007

Abstract
A synthetic fluid (Linear Alpha Olefin/Ester 90/10 blend) with a S/W ratio of 70/30 was designed and used to successfully drill a slim hole in the Garden Banks area of The Gulf of Mexico. Several service companies contributed to the operator's success in setting Gulf of Mexico records for the deepest MD (27,864â€²), TVD (26,979â€²) and setting a production liner at a record depth of 26,750â€² MD (25,772â€² TVD). This paper details the challenges met and overcome from the drilling fluids perspective in achieving these GOM records.