bluuebunny/crossref_metadata_2025_split huggingface dataset:
Tire-Suspension-Chassis Dynamics in Rolling over Obstacles for Ride and Harshness Analysis
Authors: Kerchman V. 
Published: November 2008

Abstract
The importance of improving dynamic properties is growing in vehicle development, especially as tire sidewall height is reduced. In particular, accurate prediction of tire and suspension dynamics in rolling over road irregularities is needed for evaluation of ride comfort and impact harshness in realistic driving conditions. Severity of loading from impact against bigger obstacles, such as a speed bump, deep pothole, or curb also helps to assess extreme conditions for tire, suspension, and body joint damage and durability.
In this study, a detailed tire-wheel finite element model is combined with the hub and suspension, and attached to a simplified vehicle model with a bicycle-type body and rear half. Transient event simulations of straight rolling over a bump and potholes of various geometries reveal rich dynamics of tire impact deformations and the postimpact tire, hub, and vehicle vibrations. Their relation to the tire resonant modes and rolling-impact load variations is elucidated. Simulations of curb impact and rolling over a long pothole are conducted for conditions similar to a suspension abuse test. In addition to very strong amplification of tire and suspension loads, such events produce severe local tire strains and stresses that indicate tire endurance and performance postimpact effects. An example of oblique bump impact simulation is presented as well.
Characterization of Fracture Dynamic Parameters to Simulate Naturally Fractured Reservoirs
Authors: Bahrami Hassan , Siavoshi Jamal , Parvizi Hadi , esmaili soodabeh , Karimi Mohammad Hussein 
Published: November 2008

Abstract
Fractures identification is essential during exploration, drilling and well completion of naturally fractured reservoirs since they have a significant impact on flow contribution. There are different methods to characterize these systems based on formation properties and fluid flow behaviour such as logging and testing.
Pressure-transient testing has long been recognized as a reservoir characterization tool. Although welltest analysis is a recommended technique for fracture evaluation, but its use is still not well understood. Analysis of pressure transient data provides dynamic reservoir properties such as average permeability, fracture storativity and fracture conductivity.
An infusion of geological knowledge helps reducing uncertainty associated with any well-test interpretation. The static properties of naturally fractured reservoirs such as fracture aperture, fracture spacing and fracture porosity can be obtained from processing of Image Log data.
Simulation of naturally fractured reservoirs needs defining fracture permeability, shape factor and fracture porosity in the fracture model. However, in most simulation studies, due to high uncertainties in estimating fracture permeability and shape factor values, these parameters are initially assumed in the model and they are usually tuned during history matching which can be time consuming and also affect other history match parameters. Reservoir simulation results and predictions might be inaccurate if the values of fracture properties in the model are not reliable.
This paper shows using image log data associated with welltest analysis in order to determine dynamic fracture parameters such as fracture permeability and shape factor for reservoir simulation. In this study, sensitivity analysis has also been performed on fracture permeability, fracture porosity and shape factor in a real simulation model to show importance of accurate determination of fracture parameters.

Introduction
Naturally fractured reservoirs differ from homogeneous reservoirs from many points of view: geological, petrophysical, production and economics. We may think of fractured reservoirs as initially homogeneous systems whose physical properties have been deformed or altered during their deposition. As a consequence, it is not always easy to match the behavior of these systems, specifically to forecast their production during simulation.
Exploratory Well Hits Target Successfully on the 8th Attempts in the Binak Oilfield, North of Persian Gulf
Authors: Fazaelizadeh Mohammad , Hareland Geir , Mirhaj Seyed Ahmed , Yousafi Younas , Kustamsi Andang , Shirkavand Farid 
Published: November 2008

Abstract
In the Binak oilfield, located in the north of the "Persian Gulf", seven exploratory wells were attempted to drill to the target, which is the Khami reservoir at a depth of 5600 m. Due to special conditions and problems, drilling through the formations in this oilfield was unsuccessful. The main drilling challenges include selecting correct casing depth, borehole instability due to shale sloughing and severe fluid loss and flow during drilling. These problems resulted in the unsuccessful drilling of seven exploratory wells. Therefore, the following factors were considered in designing the new exploratory well number eight.Proper selection of drilling fluids for the different hole sections by performing fluid absorption experiments on shale samples.New design of the casing and liner string.Setting casing at the right depths.Correct selection of mud weight in order to minimize severe loss and flow.Precise determination and cure of loss zones.Minimize shale sloughing by increasing mud weight
This paper shares and discusses the experience of NIOC (National Iranian Oil Company) in drilling the 8th exploratory well. It covers the successful well design as well as the methods and procedures adapted to drill this 8th well.

Introduction
The Binak oilfield is located in the north of the Persian Gulf and was discovered in 1957. This oilfield is surrounded by other oilfields such as Bibi-Hakimeh, Rag-E-Sefid, Hendijan, Bahregan SAR, and Golkhari which is shown in Figure 1. The Binak oilfield formations are the Agha Jari, Mishan, Asmari, Pabdeh, Gurpi, Bnagestan group formations, the Kazhdumi and the Khami group formations. Table 1 shows a brief description of the formations in Binak oilfield.
The present path in the drilling industry is to drill more complex wells in as cost effective way as possible. Therfore, well planning and drilling operation has to continuously improve. All technical information related to drilling wells should be considered in the well design. Major considerations must be taken for both safety and economic reasons. Two of the main considerations are that the well is drilled with an optimum mud weight and proper casing setting depth. Factors such as shale layers and abnormal/subnormal pressure formations can also greatly affect the well design.
Integrated Modeling of Fractured Low Permeability Reservoir, Shangonghe Formation, Baolang Oilfield, Northwest China
Authors: Zhou Fengde , Yao Guangqing , Wang Guochang , David Orodu Oyinkepreye , Yang QingJun 
Published: November 2008

Abstract
This paper integrated Flow Zone (FZ), single sandstone sequence, with the study of fracture, and gave a fine characterization and modeling of fractured low permeability reservoir. It pointed out that calculating the porosity and permeability for low permeability reservoir based on FZ and building the 3D discrete fracture network (DFN) distribution model integrated with the static fracture character and the density distribution of high angle fracture (HAF) and low angle fracture (LAF) are efficient methods for fractured low permeability reservoir. This brings forward the use of FZ and considerable sequence stratigraphy controlled modeling method, and brings forward to build fracture surface from point which controlled by the density distribution of HAF and LAF. The result shows the efficiency of a modeling approach for a fractured low permeability reservoir by integrating low permeability characterization and fracture study.

Introduction
It is still a challenge to model fractured low permeability reservoirs, such as characterizing the low permeability matrix, 3D fracture distribution, fracture character, fracture and matrix coupling character. 1–5
From the onset of development of Baobei Block, Baolong oilfield in 1994, the detailed sand architecture, flow zone and possible reservoir performance were known. Based on reservoir performance from exploitation, the low productivity could not be characterized by flow zone only and hence the need for an integrated characterization and modeling of the low permeability matrix and fracture is very important.
This paper is based on detailed core analysis, characterization of low permeability matrix, and model build up of the low permeability matrix controlled by multi-surface and flow zone, and construction of 3D discrete fracture network (DFN) distribution model integrated with the 2D fracture distribution, predicted by well-log response and structural curvature, and the fracture occurrence.
Seismic Expression of Loss Zones within Carbonates of the Browse Basin
Authors: Power Michael Roderic 
Published: November 2008

Introduction
This integrated study documents the drilling hazards associated with drilling through the complex overburden geology of the Browse Basin (Fig. 1). Previous drilling campaigns by other operators in the region have encountered severe problems when drilling riser-less with seawater and viscous mud sweeps through unconsolidated sands of Early Tertiary age. In an attempt to avoid these costly drilling hazards, a riser-less mud recovery system was implemented for the first time in the region. Some of the advantages that come with this system are the ability to use a drilling fluid with properties specifically designed for the formation being drilled,avoiding the build-up of cuttings around the well head, andstopping any drilling fluids being discharged into the water column.
In late 2006 the Prelude-1 exploration well was spudded. While drilling through a highly permeable section of the Oliver Formation, with the closed mud system, unsustainable losses were encountered resulting in all the drilling fluids being lost to the formation at a rate of 41 m3/hr (260 bbls/hr). Drilling progressed through the underlying section using conventional seawater and mud sweeps leading to borehole instability and repeated stuck pipe incidents leading to the well being abandoned. A new well location was identified and the well was respudded.
Life Cycle of a depletion drive and sour gas injection development: Birba A4C Reservoir, South Oman
Authors: Haynes Byron , Kaura Naveen Chander , Faulkner Andrew 
Published: November 2008

Abstract
A field in South Oman discovered in 1978 is an over-pressured sour oil reservoir. Since first oil began in 1982, the field will has gone through three stages of development during its life. These can be summarized as follows; pressure depletion, pressure maintenance with sour separator gas plus sweet make-up re-injection, pressure maintenance with sour separator gas plus sour makeup gas injection from other fields
The field produces from the A4C unit of the Ara Group intra salt carbonates. A carbonate reservoir totally encased in salt. No water has been produced to-date from this reservoir. The reservoir oil column is overlain by a gas cap and the reservoir fluid exhibits a strong compositional gradient which impacts the degree of richness required for a sour miscible gas. Development drilling and the construction of facilities proceeded with all well tubulars and facilities constructed out of carbon steel. Operation of the plant and wells occurs with high regard to the risks of sour, high pressure service, and with no integrity or corrosion has been observed to-date.
The field produced under depletion starting in 1982 through oil and gas cap expansion mechanism. The field was shut-in in 1986 awaiting gas injection. In 1993, sour separator gas combined with sweet make-up gas was re-injected as a pressure maintenance project to keep the reservoir pressure from dropping further. Upon expansion of the production station to take production from other nearby sour oil fields, more sour gas was added to the gas injection stream in 2004. Plans are developing to change the composition of the injection gas stream to achieve higher H2S levels so that the injected gas will become miscible with the A4C oil. This is designed to further increase oil recovery.
The purpose of this paper is to present the development history of this sour oil reservoir along with presenting the development approach that has been taken for injecting sour gas to increase oil recovery in this remote South Oman reservoir.

Introduction
The purpose of this paper is to present the development and performance history of a pressure maintenance project of a sour oil (H2S & CO2) reservoir developed in the Ara Salt in South Oman (Figure 1). This reservoir has undergone three stages of development with potential for miscible sour gas injection. These stages are as follows; pressure depletion (1982 - 1986), gas injection (1992 - 2004), sour make-up gas injection (2004 - to date). Estimated ultimate recovery is 30.6%. Modeling work has indicated that miscible gas injection will increase the oil recovery factor to 36% (Figure 9).
Good Practices in Progressing a Smart Well Portfolio
Authors: Lau Hon-Chung 
Published: November 2008

Abstract
Although smart wells have gained acceptance in the industry1–3, the integrated workflow needed to progress a portfolio of smart well opportunities requires systematic attention. In some cases, smart wells fail to materialize not because technologies are not ready but because of lack of participation and integration of relevant disciplines in a timely fashion.
This paper summarizes the good practices used by one operator to progress a portfolio of smart well opportunities in a number of major projects. The smart well workflow is divided into six phases: Identify, Assess, Select, Define, Execute and Operate. The objectives, technical considerations, contribution from various disciplines, key success factors and good practices of these phases are defined and detailed.
A key to successfully progressing smart well opportunities in a project is to identify and work the interfaces between the relevant disciplines. In the first three phases, the project team identifies the opportunities and assesses the feasibility of various smart well options. The optimum smart well solution is then selected through quantification of both the risks and benefits of these options using a multi-disciplinary approach. Quite often smart wells are advocated by one discipline without sufficient buy-in from other disciplines. This often leads to a weak business case and failure to adopt smart wells by the project team. In the Define Phase, attention should be placed on ensuring that smart wells components are compatible with other components in the well, subsea and surface systems. In the Execute Phase, a rigorous QA/QC program is key to successful installation. In the Operate Phase, a Collaborative Work Environment is recommended to bring data, information and people from different locations together to facilitate timely decision making to optimize the value of the asset.

Introduction
In this paper, a smart well is defined as one that consists of both downhole sensing and flow control. Typical downhole sensing devices include permanent pressure and temperature gauges, flowmeter, and distributed temperature sensing (DTS). Other devices include cableless communication and downhole geophones for detecting microseism. Typical downhole controls include interval control valves (ICV) and auto gas-lift valves. Interval control valves can be on/off, multi-positioned, or infinitely variable. They may be actuated by hydraulic or electrical control lines or both. The degree of smartness should be fit-for-purpose and defined in the early stages of a project.
A smart field4–6 usually consists of one or more of the following: smart wells, smart facilities, and an aerial reservoir surveillance program, e.g. 4D seismic. A field becomes smart when information from these technologies can be assessed, evaluated and analyzed by relevant disciplines to make timely decisions to optimize the productivity and recovery of the field. While this paper focuses on smart wells, how smart wells fit into the overall smart field implementation will be discussed.
A New Approach for Optimizing Cement Design to Eliminate Microannulus in Steam Injection Wells
Authors: Shakirah Saidin 
Published: November 2008

Abstract
Over the past few years, several papers have been published discussing the long-term mechanical durability of the cement sheath in steam injection well. Looking at this, the research is continued to find the right process flow in optimizing cement design as a new approach to eliminate microannulus in steam injection well. This process flow is based on previous experiences cementing in steam well. Duri Steam Flood is located in Sumatra, Indonesia was taken as a case study in this research. As we known, changes in downhole stress conditions that occur during the life of a steam injection well are extreme. The stresses in the cement sheath induced by the extreme temperature cycling could result in severe mechanical damage and ultimate failure of the cement sheath, potentially leading to microannulus.
From well life analysis, the result found that the steam well in Duri Steam Flood has 6% risk of cement sheath failure in less than 5 year. Because of this, the research is carried out to find the reason and solution of this failure. Firstly cemented annulus stress simulation is proposed to verify this cement sheath condition. Expanding cement is one of the proposed solutions in this study based on simulation recommendation. The behavior of the cement sheath with recently developed annulus and linear experiment is proposed. Three parts of testing for linear expanding test were conducted. Firstly, test at bottom hole static condition temperature (120 degF) and pressure (1000 psi) curing for 30 days. Then, test at bottom hole static temperature condition curing for 2 days with variation of pressure (1000 psi to 3000 psi) and test at bottom hole static pressure condition curing for 2 days with variation of temperature (100 degF to 300 degF). Magnesium Oxide (MgO) is used as an expansion additive with conventional cement slurry (Class G and 35% BWOC Silica). The concentration used is 2.7% BWOC to 7.0% BWOC. Finally compressive strength tested at bottom hole static pressure with variation of temperature (150 degF to 280 degF) at 24 hours. Therefore, a process guideline is finalized based on last cementing experiences, experiment results and cost analysis to find the most optimize cement slurry in steam injection well.

Introduction
Cementing is a part of well completion process before the well is ready for production for oil or gas from reservoir. It is very important process to make sure the cement job has to fulfill multiple conditions, but its main function is to prevent fluid and gas flow through the annulus by ensuring an impermeable bond and exhibiting sufficient compressive and shear bond strength. The sealing can be affected by various factors: poor mud removal, bad slurry properties and borehole conditions (expose to the change in temperature and pressure as always happen in steam injection well). It is also recognized that the volumetric changes of cement during hydration substantially contribute to these problems.
Preparing a Gas Field Development Plan : Tangga Barat Cluster Gas Project
Authors: Teh Yat Hong , Theseira Keith , Abdul Karim Abdul Hamid , Hashim Naqzatul Shima , Yakob A. Razak , Musa Ahmad Syrhan , Borhan Nor Aisyah , Muhamad Suhana , Sykahar M. Wakif 
Published: November 2008

Abstract
Field development planning is one of the core business processes in the upstream oil and gas industry. Before a discovered field can be developed and its hydrocarbon produced, proper evaluation and planning of the subsurface reservoirs and surface facilities are necessary to ensure that the field development plan is not only economical to undertake, but also flexible enough to cater for any deviation from the original plan during implementation as a result of inherent uncertainties in the reservoirs over the production life span of the field.
This paper describes the approach taken to prepare a Field Development Plan (FDP) for a cluster of gas fields located offshore Peninsular Malaysia. The four gas fields namely Melor, Laho, Tangga and Tangga Barat ("Tangga Barat Cluster" in short) are located within a 25 km radius of each other at a common centre. One common denominator among these fields is the presence of carbon dioxide (CO2) in its reservoirs. The Tangga Barat Cluster fields will be developed with Tangga Barat as the central processing complex, designed for a peak capacity of 440 MMscf/d of raw gas with an initial blended CO2 level of 37 mol % prior to CO2 removal. The raw gas will be processed, pre-treated and CO2 content reduced to below 8 mol % for evacuation to Peninsular Malaysia via an existing infrastructure. The key areas emphasized in the preparation of the field development plan include the business driver, resource assessment, depletion strategy, development concept and selection, managing uncertainties, appraisal requirements, reservoir management, anticipating production problems and disposal of the excess CO2.

Introduction
The Tangga Barat Cluster fields are located about 150 to 170 km northeast of Kertih, Terengganu offshore Peninsular Malaysia (Figure 1). The Tangga Barat Cluster consists of four gas fields; Melor, Laho, Tangga and Tangga Barat. In the vicinity are two producing fields, Resak which is a gas development located about 51 km southwest of the Tangga Barat field and Dulang, an oil development situated about 20 km south of Tangga Barat. The Tangga Barat Cluster fields were discovered from 1980 to 1993; they remain undeveloped due to the presence of CO2 in its reservoirs, the content level of which is beyond the gas specification required for gas sales. Since then, a total of 10 exploration and appraisal wells have been drilled before the final FDP was submitted and approved by PETRONAS, the host authority for upstream oil and gas business in Malaysia.