bluuebunny/crossref_metadata_2025_split huggingface dataset:
Feasibility Study of Air Injection for IOR in Low Permeability Oil Reservoirs of XinJiang Oilfield China
Authors: Hou Shengming , Ren Shao Ran , Wang Wei , Niu Baolun , Yu Hongmin , Qian Genbao , Gu Hongjun , Liu Baozhen 
Published: July 2010

Abstract
Xinjiang oilfield is located in the Northwest of China, in which large oil reserves have been discovered in reservoirs with very low permeability (&lt;14×10−3μm2). These reservoirs are featured with light oil in moderate depth, high reservoir pressure, but relatively low reservoir temperature (65~78°C) and low oil viscosity (&lt;10mPa•s). Primary production and limited water flooding experience have shown that the recovery factor in these reservoirs is very low due to lack of reservoir energy and poor water injectivity. Gas injection has been optioned as an alternative secondary or tertiary technique to maintain reservoir pressure and/or increase sweeping and displacement efficiency. In this study, the feasibility of air injection via a low temperature oxidation (LTO) process has been studied. Laboratory experiments were focused on LTO characteristics of oil samples at low temperature range and core flooding using air at various reservoir conditions. Reservoir simulation studies were conducted in order to predict the reservoir performance under the air injection scheme and to optimize the operational parameters. The oxygen consumption rates at reservoir temperature and IOR potentials at different reservoir conditions were assessed for a number of selected reservoirs in the region. A pilot project has been designed based on experimental data, reservoir simulation results and field experience of air injection gained in other regions of China. Issues related to safety and corrosion control during air injection and the project economics were also addressed in the paper.
Collaboration and Communication Lead to Continuous Improvement in 8 ½-in. Bit Design and Improved Drilling Efficiencies in Changbei Horizontal Application
Authors: Lee Roger , Felderhoff Floyd , Samtoy Nicolas , Richards Alun , Zeng Jun , Tan Ivan , Chen Zhiyong 
Published: July 2010

Abstract
In the Changbei gas wells of China, one of the biggest potentials for savings is in 8 1/2-in. dual-lateral horizontal drilling through the hard abrasive reservoir sandstones known as the QA sandstones. Tungsten carbide insert (TCI) roller cone bits are preferred and focus was placed on increasing distance drilled per bit. The objective of the Changbei team (a joint venture between an NOC and a major international oil company) was to achieve 375 m instead of the average 250 m, saving two bits and two trips over the 2000-m interval yielding an approximate cost saving of $100,000 USD. Due to the team's continuous performance improvement-driven culture, performance stagnation was not an acceptable risk the team was willing to take.
To address this challenge the bit service company worked closely with the operator proposing a two-pronged approach: 1)A product solution that would meet the current performance benchmark and challenges.2)Implementing a development plan to provide continuous improvement to meet future goals.
With no time for trial and error, a cross-functional team from multiple countries worked quickly developing a solution for the operator to drill the required distance at a good rate of penetration (ROP) on the first attempt. This success would not have been possible if not for the collaboration with the operator. Open access to offset dull bits and data, and clear communication of expectations and challenges were keys in delivering performance quickly.
This paper provides details of the technical aspects of the product that met the current drilling benchmark. This paper also describes the Changbei team interaction between the operator and bit service provider that led to the quick solution and the longer term development plan for continuing success.
Scale Dissolver Applications in HP/HT Gas Condensate Reservoirs
Authors: Menezes Carlos , Petrik Artyom , Graham Gordon , Simpson Caroline , Cocozza Vince , Kerr Alan 
Published: July 2010

AbstractOver recent years the scaling challenges facing many HP/HT gas condensate fields, has been highlighted and detailed works describing the challenges presented in previous SPE publications. Given the severity of the scaling regime and the extremely fast reaction kinetics, several such fields have already experienced downhole carbonate scaling and therefore remediation methods are required. Moreover, the application of acid based scale dissolvers commonly used in more conventional applications represents a significant challenge with potential for enhanced corrosion or formation damage when using these potentially aggressive fluids.This paper describes chemical selection requirements for one such field system and presents results from a range of conventional (90°C, 1 bar) scale dissolution and corrosion tests together with those from more sophisticated HP/HT (190°C; 300 bar) autoclave techniques, designed specifically to examine chemical dissolution and corrosion rates associated with the application of these fluids under severe HP/HT downhole conditions. The tests examined several different organic acid formulations including control "un-inhibited" acetic acids and various organic acids specifically formulated with corrosion inhibitors to prevent corrosion of the downhole tubulars. Results from an extensive test programme directly compare dissolution and corrosion performance measurements at both ambient and HP/HT conditions. They also serve to identify the key parameters required for the selection of such dissolution treatments, highlighting significant relative differences between different products when tested at more conventional conditions vs. HP/HT conditions. In summary the work led to the deselection of more effective dissolvers due to enhanced corrosion at HP/HT conditions. The paper therefore describes more sophisticated test methodologies for assessing scale dissolution and corrosion inhibition with these fluids under HP/HT conditions and then describes the conclusions from this work and recommendations for other similar HP/HT environments.
Appropriate Simulation of Field Treatments Using Core Flood Data
Authors: Graham Gordon M. , Kidd Sam , Fitzpatrick Robert , Wright Rob 
Published: July 2010

Abstract
Core flood experiments are an integral part of the methodology for chemical selection and the optimisation of scale inhibitor treatments, providing information on formation damage, inhibitor return profile and the dynamic retention isotherm under post flush conditions (as a function of SI, brine, pH, rock matrix, T etc.). In the absence of formation damage, the comparative inhibitor returns are often used to select the chemical prior to field treatment. However, it is recognised that there can be significant discrepancies between the core data and field data, depending on how the tests are conducted and how the data are interpreted.
In this paper, we describe the factors causing differences between the field and the core flood return. This includes inherent petrophysical differences between the small core plug and the larger near wellbore formation and differences in the saturation levels (e.g. core flood return typically at Sor) etc.. The paper also demonstrates that when considered appropriately, these differences should not impact the relative return profiles for different products.
Other, more significant aspects however, often relate to artifacts of the core test design, e.g. oversaturation with pre-flush and main treatment solutions of which multiple pore volumes are commonly applied in core tests. This work will demonstrate that such aspects can have significant consequences for the comparative inhibitor returns and moreso that these can have considerably different impacts (order of magnitude) for different chemical treatments, especially when highly retentive products are being assessed. The result being that for ill suited test protocols, selection of less effective chemicals and poor initial treatment design can result.
This paper presents examples of a series of core flood data in which the return profiles and derived isotherms show excellent agreement with field returns together with other examples were this is far from the case. We identify certain artifacts in commonly conducted core flood designs that should be avoided and recommend approaches and test protocols which allow more appropriate product ranking as well as modified modelling approaches which allow improved simulation from core to field..
Steady-State Heat Transfer Models For Fully and Partially Buried Pipelines
Authors: Ovuworie Chukwuemeka 
Published: July 2010

Abstract
Approximate analytical solutions are presented for the steady-state heat transfer from fully buried and partially buried pipelines. Although other analytical solutions exist, they suffer from limitations in the coverage of the range of burial depths and use of unphysical boundary conditions. Naturally this leads to inaccurate results, particularly, for shallow burial depths. Furthermore, heat transfer from partially buried pipes has received surprisingly little attention. Although accurate numerical solutions exist, they can be difficult to implement and time-consuming to execute.
All the limitations described above have been eliminated by the approach taken in the current study. The governing diffusion equation in this complicated geometry was solved elegantly by transformation to the bipolar cylindrical coordinate system. Convective boundary conditions connecting the pipe and ground to the fluid and ambient temperatures, respectively, were considered. Results include temperature fields and shape factors for the fully and partially buried configurations. The shape factors obtained were found to be continuous across the entire range of burial depths. Furthermore, asymptotic limits of these equations were examined to obtain expressions for when the pipe is touching the ground surface and the expressions were found to coincide.
Good success is indicated as the fully buried shape factor was found to agree with numerical results to within 2.5%. Scarcity of numerical data for partially buried pipes did not allow an analogous comparison to be done. However, it has been argued that the error in the two shape factors is the same. Consequently, the formulae given are the most accurate analytical solutions currently available. Moreover, they are computationally easier to implement and far less intensive to execute than rigorous numerical solutions, losing little accuracy.
Collaborative Operation to Face Subsurface and Operational Challenges – A Success Story of Fracturing Changbei Vertical Wells
Authors: Jin Liang , van der Bas Fred , Vitthal Sanjay , Zhu Changlong , Hu Libo 
Published: July 2010

Abstract
Three vertical appraisal wells in Changbei, Shaanxi Provice, P.R. China were drilled in 2008. It was decided to convert them to producers through hydraulic fracturing. To effectively fracture the wells, Changbei team faced several challenges: Our partner prefers the use of local service company to control cost.Within Shell, there experience in using local products to ensure the success of the operation.ShellChina did not have local specialists in conducting quality fracturing jobs without external technical support.Hydraulic fracturing was not part of the original well design consideration. This imposed some challenging fracture design constraintslimiting the flexibility of selecting the optimum engineering parameters for the treatments.
A task force consisting of ShellChina subsurface and well service personnel, Shell Global Stimulation Delivery Team (SGDT) members, and regional stimulation focal point had been established. The team had quickly resolved most of the issues for the operations. The key activities are: Established working structure among ShellChina, SGDT, Shell regional expert, PetroChina employees, and local service companies.Test local fracturing fluid systems and work with the provider to establish a QA/QC procedure.Optimized design and execution based on the well and reservoir conditions.Development and implementation of a comprehensive quality program. This included ∘Strict onsite HSSE practices and QA/QC and a close working relationship with local service company.∘Rigorous lab testing of all fluids and materials.∘Inspection on local service company's equipment to meet global HSSE and technical standards.
The first well (Well A) encountered initial flow back difficulty due equipment error, but eventually came back as designed. The operation on the second well (Well B) is a full success. This well is among the best vertical wells hydraulically fractured in the block.
Determining Multilayer Formation Properties from Transient Temperature and Pressure Measurements in Commingled Gas Wells
Authors: Sui Weibo , Ehlig-Economides C. , Zhu Ding , Hill A. D. 
Published: July 2010

Abstract
With the evolution of downhole permanent monitoring techniques, transient temperature and pressure data can play an important role in reservoir description due to their inherent real-time characteristics. Previous studies presented a completely new analysis technique for quantifying permeability and altered zone permeability and radius for multiple commingled layers. However, the previous model mainly applies for single-phase oil flow.
A new wellbore/reservoir coupled flow model has been developed for multilayer commingled gas reservoirs including both damage and non-Darcy skin in each commingled layer. The non-Darcy effects are considered as permeability alteration and are incorporated to the reservoir flow model by using Forchheimer equation. Additionally, this coupled flow model can consider the pressure drop due to friction and kinetic energy changes in wellbore over the producing layers, which yields more accurate transient layer flow rate allocation. This coupled flow model is used to provide the wellbore pressure distribution and the radial reservoir pressure gradient for the coupled wellbore/reservoir temperature model. The temperature model is formulated using wellbore and reservoir energy balance equations considering subtle thermal factors such as Joule-Thomson effect and also using fluid properties which are dependent on in-situ pressure and temperature. The inverse method is adopted from previous study directly and is used for determining formation properties by doing nonlinear regression.
The mathematical model is solved numerically and used to study the sensitivity of transient temperature behavior to formation properties. The results show that transient temperature behavior in the wellbore at strategic locations is very sensitive to formation property values, and has some interesting characteristics similar to oil reservoirs. However, due to the non-Darcy effects, each producing layer in multilayer gas reservoirs has non-Darcy skin more or less, which makes the transient temperature behavior in gas reservoirs show more complexities than the oil reservoir case. In the end, two hypothetical examples are presented to show the performance of the inverse method. The regression results show that the damage skin location and magnitude can be determined correctly using the proposed testing method.
The Use of Huff and Puff Method in a Single Horizontal Well in Gas Production from Marine Gas Hydrate Deposits in the Shenhu Area of the South China Sea
Authors: Li Gang , Moridis George J. , Zhang Keni , Li Xiao-sen 
Published: July 2010

Abstract
Shenhu Area is located in the Pearl River Mouth Basin, the northern continental slope of the South China Sea. It is expected that Shenhu Area will become a strategic area of gas hydrate exploitation in China. Based on currently available data from site measurements, including water depth, thickness of the Hydrate-Bearing Layer (HBL), sediment porosity, salinity and pressures and temperatures at key locations, it is possible to develop preliminarily estimates of the gas production potential by numerical modeling.
We used measurements of ambient temperature in the sediments to determine the local geothermal gradient. Estimates of the hydrate saturation and the intrinsic permeabilities of the system formations were obtained from direct measurements. The hydrate accumulations in Shenhu Area are similar to Class 3 deposits (involving only a HBL), and the overburden and underburden layers are assumed to be permeable. These unconfined deposits may represent a large challenge for gas production.
In this modeling study, we estimated gas production from hydrates at the SH7 drilling site of the Shenhu Area by means of the stream huff and puff method using a single horizontal well in the middle of the HBL. The simulation results indicate that the hydrate dissociated zone expands around the well, and the hydrate formation occurs during the injection stage of the huff and puff process. The higher temperature of the injected brine appears to have a limited effect on gas production using the huff and puff method. Reasonable injection and production rates should be adopted to avoid the over pressurization and depressurization during each huff and puff cycle. Production is invariably lower than that attainable in a confined system, and thermal stimulation is shown to have an effect over a limited range around the well. The sensitivity analysis demonstrates the dependence of gas production on the level of the increment of the injection and production rates of huff and puff process, the temperature of the injected brine and the existence of brine injection during the injection stage.
Natural Frequencies Analysis of Hyperstatic Integration Marine Drilling Riser
Authors: Zhang Wei , Gao Deli 
Published: July 2010

Abstract
The marine drilling riser is a key outfit which links the wellhead above seabed with the drilling vessel together and it is also a fluid passageway during drilling. It can be regarded as a special beam-column for the reason that it is surrounded by seawater and filled by drilling fluid, while there is tension load which varies along its axial direction. Therefore, the hydrostatic pressure effect on riser must be considered by the LAME formula.
Thickness of the main tube can be reduced because the peripheral lines of hyperstatic integration (HSI) marine drilling riser may share axial loads. The structure change into HSI pattern will affect the bending rigidity of marine drilling riser which is a significant factor to calculate the natural frequencies. The factors affecting natural frequencies of the marine drilling riser include axial loads shared by peripheral lines and changing of the main tube thickness. This paper is focus on analyzing the influential factors by using finite element method, and solves the differential equation which includes influential factors by numerical method to achieve a simple formula to calculate natural frequencies of marine drilling riser. Because the natural frequencies of HSI marine drilling riser decrease, the marine drilling riser can avoid the frequency lock and resonance, and improve dynamic behavior so as to reduce operation cost and risk significantly.
Choice of Landing String under Ultra-Deepwater Drilling Condition
Authors: Zhang Hui , Gao Deli , Tang Haixiong 
Published: July 2010

Abstract
It has been proofed that 149.2 mm landing string used in ultra-deepwater drilling and completion operations has an advantage over 168.3 mm string in operability and space saving. This paper presents the comparisons between these two landing strings in mechanical behavior. Under the ultra-deepwater conditions, the slip crushing capacity is one of the critical limitations for landing string to run longer and heavier casing to deeper depth. Bending stress is also an important consideration in landing string design especially under the condition of non-riser casing running operations since the landing string will sustain the current force and drilling ship offset. Dynamic load induced by vessel heave may be serious because the self-vibration frequencies will become smaller as the water and well get deeper. Through the comparisons between 149.2 mm string and 168.3 mm string with the same tension strength in their loads and stress it will be helpful to choose a more suitable landing string under ultra-deepwater condition.
The results show that 149.2 mm string has a larger slip crushing load than 168.3 mm string because of its smaller outer diameter. There is no obvious difference between these two strings under the condition of vessel offset. But 149.2 mm string has smaller bending stress than that of 168.3 mm string by the action of current. The axial vibration characteristic of pipe string is related to its elastic modulus, density of material and cross section area, so the self-vibration frequencies and dynamic axial load caused by vessel heave of these two strings are similar. On the whole, 149.2 mm string is more suitable used in ultra-deepwater operations in comparison with 168.3 mm string considering its mechanical behavior.
The Research and Application of Ultra High Temperature Fracturing Technology for Glutenite Formations
Authors: Guo Jianchun , Yue Yingchun , Song Mingshui , Li Xue , Lu Yunxiao 
Published: July 2010

Abstract
The temperature of some glutenite reservoirs of Shengli oil field located in the east of China reaches up to 180°C, and it would exceed 190°C in the subsequent exploring reservoirs, even close to 200°C. Nevertheless, neither the fracturing fluid system nor the down hole instruments can satisfy the fracturing technology demands at such high temperature, which restricts the effective exploration and development of high temperature deep reservoirs in Shengli oil field. Therefore, it's necessary to launch the research into ultra high temperature fracturing technology of glutenite reservoir, and to carry out field application.
Through additive development, performance optimization and systematic performance evaluation, this research firstly developed the ultra high temperature fracturing fluid system enduring 200°C, which could maintain the viscosity of 100–110 mPa.s when it was continuously sheared for 120min under the conditions of 198°C and 170s−1, and laid the foundation for ultra high temperature fracturing. Based on the analysis of the configuration of high temperature and high pressure packer, the self-sealing and compression packing elements were designed. And then the ZY541 packer enduring the pressure of 70MPa and the temperature of 180°C was firstly invented, which provided the apparatus guarantee. The research results were applied to well ZG63, and the construction continued for 120 minutes at the highest construction temperature of 184.6°C in China, which created a new fracturing record, validated the reliability of ultra high temperature fracturing fluid and down hole instruments, and realized the important breakthrough of ultra high temperature fracturing technology as well. This research solved the key technology difficulties of deep and ultra high temperature fracturing in China, upgraded the level of fracturing technologies in this type of reservoirs, and effectively promoted the exploration and development of ultra high temperature reservoirs in China.