bluuebunny/crossref_metadata_2025 huggingface dataset:
Use of Multi-Sample Characterization Method for EOS Tuning to Model Full Field Crude Oil Properties
Authors: Khajooie S. , Shahrabadi A. , Hamid K.
Published: July 2010

In compositional simulation of oil and gas reservoirs, equation-of-state (EOS) methods are seeing increasing usage for phase equilibrium calculations. EOS compositional reservoir simulation is an accurate and powerful means to model complicated phase and flow behavior when the displacement process depends on pressure and fluid composition. Many field development projects have strong composition dependence, such as miscible gas injection for oil reservoirs or liquid recovery under lean gas injection for condensate reservoirs or water-alternating-gas injection.

This paper presents characterization of some crude oil samples from an Iranian reservoir using the Peng-Robinson Equation of State (PR-EOS) to arrive at one EOS model that accurately describes the PVT behavior of crude oil produced from the different wells in the reservoir. The multi-sample characterization method is used to arrive at one consistent model for crude oil for the whole reservoir.

However, uncertainties still exist that are associated with the use of an EOS to model petroleum reservoir fluids because of the complicated nature of such fluids and limitations of the most commonly used EOS's. Tuning the adjustable EOS parameters to match experimental fluid PVT data is a common practice. The tuning procedure for the EOS is done systematically by matching the volumetric and phase behavior results with laboratory results. Also, a consistent C7+ pseudo component split using the Whitson splitting method is used for all samples to arrive at a consistent model for crude oil for the whole reservoir.

Results showed a good agreement between model predictions and laboratory data. Also the results demonstrate that multi-sample method has high ability to provide one EOS model for the crude oil using PVT test results from different wells. The EOS model developed for this particular field may be used in reservoir simulation studies to optimize hydrocarbon recovery.
A New Method to Evaluate the Gas Migration for Cement Slurries
Authors: Haijin Zhu , Jiansheng Qu , Aiping Liu , Jianlong Zou , Jiaxing Xu
Published: July 2010

The oil industry wrestled with the problem of gas migration after cementing for many years. As yet an extensive research has been carried out on the problem of gas migration. A lot of corresponding slurries were developed, and most of them have been used successfully in some districts but not total alleviation of the problem. The main reason is the lack of a method to evaluate the gas migration of cement slurries when considering actual well parameters.

In this paper, based on previous art of the method to scale-down well parameters to laboratory for more realistic testing of cement recipes, by establishing the method of measuring cement slurries’ static gel strength to gain the development of the annular column hydrostatic pressure, a new method to evaluate the gas migration for cement slurries was developed. This method depends on the decline of upper annular column hydrostatic pressure, and can be used to evaluate the ability of the cement slurry in controlling gas migration. Several cement slurries were investigated by this method. The laboratory tests were presented with good repeatability, and could be used to test the ability of cement slurries in controlling gas migration.

In field applications, this method has been used in designing cement recipes when cementing gas wells in Chuanyu Area of China. The ability of cement slurries in controlling gas migration has been tested. The field results were consistent with the laboratory tests, and demonstrated the method could be used to guide cement slurries design effectively.
The Study of The Circulation of Drilling Foam
Authors: Wan LiPing , Meng YingFeng , Li YongJie , Wang Jian , Shu XiaoBo , Zeng QingMing
Published: July 2010

The circulating utilization of foam fluid is available, which was based on some of the lower carbon alcohols presenting the characteristics of both strong defoaming and weak restricting foam ability, and through optimum selection of formula by indoor experiments. The recirculable feature of four kinds of alcohols on unstable foam (0.6%K12), stable foam (0.6%K12+0.2%XC+0.2%HV-CMC) and stiff foam (0.6%K12+0.2%XC+0.2%HV-CMC+5.0%bentonite) was comparatively investigated. The circulating foam ability of the mixed system of alcohol D and tributyl phosphate (TBP)was studied on the self-made foam fluid circulation experimental device. The results show that alcohol D is the most suitable defoamer in four kinds of alcohols. The mixed system of alcohol D and TBP can recycle stable foam at least 8 times. With increasing cycle number, both foam volume and half life decrease, in which foam volume falls gradually and half life declines more dramatically. After 8 runs, the volume of foam falls from 470ml to 420ml and half life declines from 28.7min to 15.8min, but both of them can fill the actual requirements of on-site drilling.

This paper is the first in a series of studies designed to bring forward foam circulating utilization in underbalanced drilling by adding alcohol as defoamer. The goal is to understand the mechanism of foammg-defoaming-refoaming of alcohol better, and extend air foam drilling techniques in suit region.
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

Xinjiang oilfield is located in the Northwest of China, in which large oil reserves have been discovered in reservoirs with very low permeability (<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 (<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

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

Over 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

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

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

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

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

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

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

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

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.
Application of Super High Density Drilling Fluid under Ultra-High Temperature on Well Shengke-1
Authors: Yu-zhi Xue , Gong-rang Li , Bao-feng Liu , Zhang Jinghui
Published: July 2010

The Well Shengke-1 is one of ultra-deep wells with total depth of 7026m, bottom hole temperature of 235 °C and more than pressure of 100MPa. Ultra-deep well drilling fluid faces many serious challenges. Severe engineering problems would arise if the drilling fluid is not treated properly and even the success of the well is determined by the drilling fluid. The difficulties including complex formation, long barefoot borehole, and ultra-high temperature were confronted. The stratums of φ215.9mm hole included section KongDian 1 and section KongDian 2, in which the clay minerals in upper shale stratum consist of mainly mixed layer of inordinate illite and montmorillonite. Therefore, the troublesome conditions could probably occur during drilling. The open-hole interval was as long as about 3000m, and pressure indices of formations varied enormously. In upper stratum, after high pressure brine formation had been drilled at 4598m, the density of drilling fluid increased to 1.83g/cm3. Meanwhile, the pressure index of under-stratum was about 1.30g/cm3, so lost circulations had happened many times in high differential pressure. The high temperature of the drilling would induce complicated reaction between the clay and drilling fluid so as to slough of the clay. During drilling yield point and gel strength increased quickly with the effect of high temperature. The Poly-sulfonate plugging and anti-sloughing (5155~4598m), high density poly-sulfonate non-invasive (4598~5800m), and ultra-high temperature and super high density drilling fluid(5800~7026m) had been used in 215.9 mm interval of the well, respectively. The drilling fluid kept stationary for a long time during completion which caused drilling fluid thickening, dehydration and mud cake thickening. The solid-free anti-high temperature completion fluid was used to guarantee the success of logging and casing. It was proved in the field application of Shengke1 that the drilling fluids exhibited a series of advantages, including excellent rheology behavior, good thermal stability and low filtration rate. It was easy to treat, formulate and maintain, and could deal with the salt and brine contamination. It had been stable under 235°C of the BHT in Shengke1, the highest temperature encountered in China at that time, and guaranteed the well to be completed successfully.
Influence of Temperature on Water and CO2 Flooding of Asphaltenic Chalk Reservoirs: Experimental and Simulation Case Study
Authors: Hamouda A. A , Chukwudeme E. A. , Tabrizy V. Alipour
Published: July 2010

Injection of seawater into low permeable and high porous chalk reservoirs has received considerable interest as a method for enhanced oil recovery with a great challenge due to unfavorable wetting conditions, i.e. low water wetness in the matrix block.

The paper addresses two parts. The first part is related to flooding with water and CO2. The study revealed the efficiency of the CO2 flooding following water injection; however it is interesting to observe that the difference in the oil recovery is minimal at the start of CO2 injection after water injection. The oil recovery then showed vast increase in oil recovery with CO2 injection after the initial period.

The second part addresses the effect of the temperature on non-asphaltenic and asphaltenic oils showing the preferential water composition on enhancing asphaltenic oil recovery from matrix. The study demonstrates the effect of CO2 and the preferential water composition on recovery from the matrix, which concluded that the CO2 reversed the ranking of the water composition on oil recovery suggesting asphaltene/ionic interaction.
Improvement and Application of Bowers’ Velocity Effective-Stress Method in Pore Pressure Estimation
Authors: Ji Rongyi , Fan Honghai
Published: July 2010

In pore pressure estimation, Bowers’ velocity effective-stress method has always been a kind of computing model can not be ignored, use it to estimate pore pressure with high accuracy. Bowers pointed out that rock properties change or overpressure could cause velocity reversal data to diverge from the main compaction trend, and overpressure results from undercompaction or fluid expansion mechanisms. In the process of continued increase in effective stress, velocity-effective stress relations define the original compaction curves. As the effective stress decreases, a sharp decline in sonic velocity, velocity-effective stress relations define the rebound curves.

According to this theory, Bowers set up loading and unloading two pressure models, but in the study, we found a shortcoming in the Bowers’ unloading model. After Improvement, we arrived at a more reasonable theoretical model. In the application of well Moshen-1, we have verified its validity, and have achieved remarkable results.
Seismic Acquisition Techniques for Loess Area in Western China
Authors: Li Dajun , Sun Jianku , Chen Kaiming , Zhang Xiaobin
Published: July 2010

The obduction zone of Kunlun mountain foreland in southwest Tarim basin in China is covered with thick loess whose thickness changes from several decade meters to 500m, even up to 600m in some area, so, the S/N of seismic data acquired in this area is very low due to serious absorption and attenuation of seismic wave and develops strong secondary interference. Being extruded and compressed by Kunlun Mountains, the topography of this area changes rapidly, the subsurface structure is steep and complex, and the faults are very developed, which lead this area to be one of the most difficult areas to do seismic exploration in the world. The conventional seismic exploration techniques used previously can't meet the requirements of the oil/gas exploration any more, and in the area since 1978, after the Kekeya oilfield was discovered, there has been no breakthrough made. Since 1999, several seismic technique tackling studies on Kekeya edge have been carried out, and wide line receiving and source array with deep holes have been applied, but the effects are not good. In recent years, on the basis of the previous rounds of seismic exploration tackling results in the thick loess area, new research has been conducted, and seismic data with relatively high S/N been acquired, which can meet the requirements for geological interpretation. Moreover, aimed at this thick loess area, seismic acquisition technique series have been developed, and great breakthroughs have been obtained for seismic exploration in loess area, and the first-grade rate of the seismic data increased by about 20%, all of which made a solid foundation for seismic exploration of loess area in southwest Tarim, and these technique series have some reference values for seismic exploration in the similar areas.

The paper introduces some new technical achievements and knowledge for seismic acquisition in loess area of southwest Tarim basin, mainly including: (1) wide-line survey technique with high fold and long receiving spread is applied to increase the effective fold on the target horizons, and improve the quality of the seismic section; (2) source array technique with long pattern length and small charge size is applied to enhance the downgoing energy of the seismic wave; (3) long array receiving technique is applied to suppress the lateral interference and improve the signal sensitivity.
Estimate of Permeability of Fracture Corridors/Networks: from Data Acquisition to Reservoir Simulations
Authors: Zhang Xing , Koutsabeloulis Nick
Published: July 2010

An empirical flow model, based on the observed fracture networks and corridors of the deepwater clastic systems of Clare Basin, Ireland, shows that fracture enlargement at intersections increases the vertical flow through fracture corridors. In vertical fracture corridors, flow is dominantly controlled by fracture density and aperture, but this work also shows a significant influence from fracture intersection openings.

Only connected fracture networks contribute to field horizontal permeability, while both isolated and connected fractures contribute to vertical permeability. In this field, horizontal fracture flow needs a minimum fracture density about 4.5 m−1; below that critical density, no field horizontal fracture flow exists. For fracture aperture of 0.1 mm, field horizontal intrinsic fracture permeability can be estimated by an empirical equation: kIH(cm2) = 5×10−9d3.802 (m−1) for fracture density between 4.5 and 7 m−1; where fracture density is between 7 and 20 m−1, the empirical equation kIH (cm2) = 2×10−7d1.978 (m−1); where fracture density is above 20 m−1, kIH is close to field vertical intrinsic fracture permeability (kIV) because more and more fractures are connected to form flow channels.

The workflow introduced here estimates field scale-fracture permeability using discrete fracture networks (DFNs) for reservoir simulations from seismic and well logs. We estimated the vertical permeability of both simulated fracture networks and natural fracture networks from the sediment rock exposures in the English Lake District, estimating both vertical and horizontal intrinsic fracture permeabilties based on fracture density (d).
Seismic Prediction of Carbonate Reef or Oolitic Reservoirs in Central Sichuan Basin
Authors: Deng Ying , Li Yalin , Li Zhirong , Zhang Yanchong , Jiang Wei
Published: July 2010

According to previous geological achievements, the development of the reef or oolitic reservoir is closely related to sedimentary facies. The reef or oolitic reservoir belongs to hidden lithologic trap, and the sedimentary evolution process and palaeogeomorphology settings of open sea platform-ocean trough sedimentary facies belt formed in the Late Permian in Sichuan basin are very complicated. As the platform continuously increased, ocean trough gradually disappeared in Feixianguan Period. Furthermore the physical properties of the reef or oolitic reservoirs have features of lithologic traps, such as strong heterogeneity and complex gas-water relationships which make it very difficult for seismic prediction. In recent years, we developed sedimentary facies prediction technique as well as seismic prediction technique series of carbonate reef or oolitic reservoir by tracking on seismic prediction techniques of carbonate reef or oolitic reservoir based on seismic facies.

First, we made fine horizon correlation and sequence stratigraphy analysis, then simulated the multicycle sedimentary evolution process from the Feixianguan to Changxing period. After that, we applied the following techniques: forward modeling, layer flattening, ancient landscape restoration and seismic facies pattern. Finally we established different sedimentary facies belts and made seismic prediction. According to the analysis on the reservoir features of logging data, we established reservoir identification pattern which expressed low gamma and low acoustic impedance. Then we adopted facies-controlled inversion technology, carried out reservoir prediction in the favorable facies belts of reef and oolitic reservoir; finally made gas and water detection with such techniques as waveform decomposition and frequency alias attenuation and so on.

The carbonate reef or oolitic reservoir prediction techniques have been widely applied and good drilling effects have been obtained. In central Sichuan, 40 exploratory wells have been deployed after using these techniques prediction results. Presently, 22 wells have been completed and among them 20 wells have drilled reef or oolitic reservoir. By using these techniques, the distribution of reef or oolitic reservoir was ascertained further in the two banks of Kaijiang-Liangping trough, and the west bank of western Hubei trough. And the hydrocarbon exploration fields in Sichuan Basin were widened.
EOR of Superheated Steam Injection in Shallow Heavy Oil Reservoir: A Case Study
Authors: Wu Yongbin , Ma Desheng , Liu Shangqi , Wang Hongzhuang , Zhao Xin
Published: July 2010

This paper demonstrates a case study of the superheated steam injection methodology studied and utilized in the North Кенкияк oil field. The methodology is studied from its mechanisms of enhanced oil recovery by approaches of reservoir engineering, in-house experiment and numerical simulation, which indicate that by injecting the superheated steam, the advantages of rock wettability conversion, more heat enthalpy, larger specific volume and latent heat of vaporization of superheated steam would result in the better production and economic performance. Pilot test wells reinforced the study and the field application is planed and optimized.
Exact Non-Newtonian Flow Analysis of Yield Stress Fluids in Highly Eccentric Borehole Annuli with Pipe or Casing Translation and Rotation
Authors: Chin Wilson , Zhuang Xiaoying
Published: July 2010

Non-Newtonian flows in highly eccentric annuli with cuttings beds, washouts and fractures, encountered in cementing and managed pressure (and underbalanced) drilling, are solved without crude slot flow and hydraulic radius approximations. The nonlinear partial differential equations, written to customized, boundary-conforming, curvilinear coordinate grid systems providing high physical resolution in tight spaces, are solved exactly with no-slip conditions, and detailed velocity, apparent viscosity, shear rate and viscous stress fields are computed for pressure drop, hole cleaning and other applications. For fluids with yield stress, well known uncertainties related to plug zone size and shape are fully resolved using generalized Bingham plastic and Herschel-Bulkley relations applicable across transition boundaries (determined iteratively as part of the solution) reaching into and across the plug. Two-dimensional, single-phase, steady flow simulations, solved rapidly using finite difference methods, provide detailed numbers and color displays for all physical quantities within seconds, with excellent numerical stability for all fluid types with and without yield stress. Formulations for steady-state casing or drillpipe longitudinal translation and rotation are described, and extensions to model transient incompressible effects associated with starting, stopping and periodic movement, important in evaluating cement-mud displacement efficiency, axial-helical cuttings transport, swab-surge, and jarring remedies for freeing stuck pipe, are discussed. Practical problems are presented and the advantages over existing models are described. These methods extend those in the author's books Borehole Flow Modeling in Horizontal, Deviated and Vertical Wells (Gulf Publishing, 1991) and Computational Rheology for Pipeline and Annular Flow (Elsevier, 2001).
The Effect of Casing Eccentricity on the Casing Stability Analysis of a Wellbore Drilled in Gas Hydrate Bearing Sediments
Authors: Salehabadi Manoochehr , Jin Min , Yang Jinhai , Ahmed Rehan , Tohidi Bahman
Published: July 2010

Conductor pipe is a surface casing installed in the first few hundred meters in deepwater drilling operations (tens of meters in onshore operations) and it is used to prevent borehole collapse (and protect unconsolidated surface formations against washing out by drilling mud). Gas hydrate bearing sediments found typically near to the seafloor in deepwater environments are very soft and unconsolidated formations. Hole enlargement and wash-out are problems during the drilling these types of formation. As a result, the casing eccentricity is inevitable in the case of borehole washout (in particular if there are not enough centralizers placed on the casing).

The circulation of hot drilling mud during subsequent drilling operations or production of hot hydrocarbon after completion of the wellbore will dissociate gas hydrates in the formation behind the casing. Water and gas resulted from gas hydrate dissociation cannot flow away if the permeability of the formation is very low causing high pore pressure to trap behind the casing. The trapped pore pressure in combination with the casing eccentricity may endanger the stability of the casing depending on the magnitude of trapped pore pressure, degree of casing eccentricity and the mechanical strength of the casing. As a result, the development and drilling operations in deepwater environments can be challenging if there are gas hydrate bearing sediments.

In this communication, a numerical model is developed using a finite-element code in order to analysis the casing stability of the wellbores drilled in gas hydrate bearing sediments. The model is used to analysis the casing stability of the wellbore under uniform and non-uniform loadings. The non-uniform loading is introduced in the model by considering the presence of eccentric casing together with the pore pressure increase due to gas hydrate dissociation.

The results of the model show that the casing eccentricity is an important issue in the casing stability analysis of the wellbores drilled in gas hydrate bearing sediments in deepwater environments. The higher degree of casing eccentricity, the higher the magnitude of stress generated in the casing during subsequent operations, which may lead to casing collapse
A Fast and Efficiency Numerical Simulation Method for Supersonic Gas Processing
Authors: Dengyu Jiang , Eri Qitai , Wang Changliang , Liu Huoxing , Yuan Yao
Published: July 2010

Supersonic swirling separation technology is an innovative gas conditioning technology to separate heavy hydrocarbon and water vapor from the natural gas. The Laval nozzle, where the condensation occurs, is used to generate supersonic flow and achieved a high degree of supersaturation in natural gas dehydration unit. Therefore, the nozzle shape has a strong impact on the non-equilibrium phase transition and plays a decisive role to the distribution of the nucleation and the growth rate. To optimize the structure of the Laval nozzle and achieve higher separation efficiency, numerical simulation plays an important role in accelerating development cycles and cutting down the cost of experiment.

In this paper, to avert the complexity of using the multiphase models and real gas model, a quick and efficiency method is validated and used to determine the location of the nucleation zone and the droplet growth zone.

The corrected Internally Consistent Classical Theory (ICCT) model and Gyarmathy model (gya82) were employed to the numerical simulation of a condensing Laval nozzle flow by coupling the N-S equation and condensate mass equation at different nozzle pressure ratios (NPR) and initial supersaturations. The results show that, in a supersonic expansion Laval nozzle flow, high cooling rate results in a high value of supersaturation and nucleation rate. When condensation occurs, the flow is affected by the latent heat released and the total temperature is increased. This method can accurately predict the distribution of the condensing flow parameters, find an optimized flow state to obtain larger droplet, and assure the latent heat released is moderate to maintain a steady flow. Finally, this method is applied to the numerical simulation of a full-scale supersonic swirling separator flow field under different work conditions.