bluuebunny/crossref_metadata_2025_split huggingface dataset:
Means to Guard Environment from Pollutants & Hazards, a Tailored Risk Assessment Scheme to Control Failures of Hydrocarbons-Transfer Pipelines
Authors: Kandil Mohamed Essam , Anwar Wael Mohamed 
Published: December 2007

Abstract
Hydrocarbon transfer pipelines that passing/traversing across protected areas have always the risk of sudden failure due to unseen internal corrosion that may cause damage to the surrounding environment. Therefore, it is necessary to maintain the integrity of hydrocarbon transfer pipelines especially, aged pipelines in order to minimize the risk of its failures, avoid oil spill, protect the environment from pollutants and achieve a proactive pipeline failure control.
In general, internal corrosion could be attributed to the increased water content in operations, the decreased flow velocity, CO2 corrosion, under-deposit corrosion or microbiologically influenced corrosion (MIC). Therefore, in order to minimize/avoid MIC in pipelines, it will be necessary to apply a corrosion management program in order to preserve and assure the integrity and serviceability of pipelines.
This paper presents a pipeline risk assessment program that was designed to manage corrosion, control pipeline’s failures and to assure a renovated pipeline system. This program includes practical techniques to 1) refurbish a doubtful pipeline, 2) determine exact condition & remaining life of a pipeline and 3) to make active pipeline maintenance. This technique is successfully implemented in GUPCO Oil Company and proved its capability to be a powerful tool to evaluate & maintain the overall integrity/strength of GUPCO pipelines network. It is simple now for pipeline operators to identify areas of greatest impact to the environment & safety and to respond with the necessary course of actions to remedy the deficiencies. Thus, they succeeded in maximizing economic returns for GUPCO shareholders, protecting the safety of employees/community, minimizing risk to the environment and finally complying with the laws and regulations of Egypt.
A Successful Project of Progressive Exploration and Development for Shallow Gas Reservoir in Chenjiazhuang Arch
Authors: Sheng Ruyan , Cao Zhongxiang , Xiang Xiyong 
Published: December 2007

Abstract
Aimed at the characteristic that gas-bearing formation of shallow gas reservoir (SGR) shows bright spot on seismic cross-section, integrative technology research combining exploration and development has been developing in Shengli Oil Fields. After several years’ practice, a series of techniques of progressive exploration and development with high benefit for SGR have been created. Studies and practice prove that bright spot on conventional seismic section has nature of multi-solution, i.e. some kinds of reservoirs, such as lithologic reservoir, hydrogenous sandstone, gas bearing hydrogenous sandstone and gas bearing sandstone, all show the characteristic of bright spot. In order to solve this problem, special purpose processing involving 3D, G-log and amplitude versus offset (AVO) is used to distinguish between real bright spots and false ones. Four gas-bearing regions including Yanjia, Chenjiazhuang, Gunan and Sanhecun have been discovered and put into production since 1988. 162 probable bright spots have been found, and 60 new wells drilled with 56 successful wells. Drilling success ratio advances from 55% to 93.3%. Incremental proven gas bearing area is 48.2 km2 with gas initially in place 4.304×10 9m3, and gas rate is 375× 103m3/d. The spread application for this technology has been seeing considerable economic benefit, and it provides practical experience for exploiting such kind of reservoirs also.
Progressive exploration and development utilizing technology of seismic bright spot accelerates the step of getting production. Four steps, including special purpose processing and seismic data interpretation, programming development plan and fulfilling drilling and gas lines construction, gaining gas productivity and submitting proven reserves, are all accomplished in the same year. This paper introduces a typical example for the course of progressive exploration and development in Chenjiazhuang Arch.
Modeling a Rich Gas Condensate Reservoir with Composition Grading and Faults
Authors: Liu J. S. , Wilkins J. R. , Al-Qahtani M. Y. , Al-Awami A. A. 
Published: December 2007

Abstract
The Hawiyah Jauf Reservoir is a complex structural-stratigraphic trap located along the east flank of the uplifted Ghawar structure. The two important aspects of this reservoir are fieldwide composition variation and reservoir compartmentalization. The reservoir fluid samples obtained during developmental drilling show remarkable differences in fluid properties and condensate yields. The condensate yield of collected samples varies form more than 250 STB/MMscf to less than 100 STB/MMscf, and the reservoir fluid at the gas-water contact exhibits the near-critical behavior. Furthermore, the complicated fault system subdivides reservoir into several major compartments.
In order to model the fieldwide composition variation, all fluid samples must be characterized reasonably well by using one equation of state (EOS) fluid model. An eight-component EOS fluid model has been generated based on four fluid samples. A geological model was built to honor the faults that were interpreted from the recent 3D seismic survey.
A series of prediction runs are planned to forecast the reservoir behavior and hydrocarbon recoveries under various operational scenarios including simple depletion as well as cycling at different stages of production. Sensitivity runs are also made to investigate the impact of uncertainties associated with geologic and reservoir properties.
Pore Pressure Prediction Data Using Seismic Velocities and Log Data in the Offshore Nile Delta, Egypt
Authors: Badri M. A. , Sayers C. , Hussein R. A. , Graziano A. 
Published: December 2007

Abstract
One of the main challenges in the deep water of the offshore Nile Delta is the ability to predict pore pressure. In this difficult environment the rig cost and risk is high requiring an accurate estimate of pore pressure for safety concern, optimizing mud weights, and casing program. Pore pressure prediction has been based in the past on after drilling results and recently while drilling using log data such as resistivity and sonic measurements. Pre-drill pore pressure estimation has been obtained from transform models using seismic interval velocities. However, the accuracy of this estimate of pore pressure is directly related to the reliability of these interval velocities and the assumptions underlying the various pore-pressure models used. The availability of the 3-D velocity data from 3-D seismic surveys can provide valuable information that can be used to produce 3-D pore pressure cube.
In this paper, a feasibility study has been carried out on exploration wells in the offshore Nile Delta, Egypt, to estimate pore pressure using borehole seismic velocities. Two examples of highly pressured and normally pressured formations in the offshore Nile Delta will be presented. The first well had an unexpectedly high-pressure gradient (15.4 ppg, 1850 kg/m3) in the Pliocene formation section at depth less than 2000 m, resulting in a significant increase in the mud weight, and a well 28 days above the AFE. The second well was drilled based on similar mud weight properties as the first well but resulted in severe losses and well 15 days above the AFE. A velocity-pore pressure transform has been derived and results were applied on 2D seismic section.
The ability to predict pore pressure before drilling from 3D seismic velocities provides valuable information to optimize drilling strategy and significantly reduce well cost in deep water environment.
Efficient Technology Application to Optimize Deep Gas Well Completions in the Khuff and Jauf Formations Requiring Hydraulic Fracturing in Saudi Arabia
Authors: Solares J. Ricardo 
Published: December 2007

Abstract
The first phase of an accelerated project to develop Saudi Arabia's deep gas potential has been sanctioned, and a large number of new gas producers are currently being drilled and completed. A number of wells have been either acid or hydraulically frac’d, and preliminary production tests have shown significant productivity increases resulting from this type of stimulation. Consequently, plans have been finalized to frac most existing and future wells in this development.
Fracture initiation pressures average 16,000 psi. at downhole conditions, and H2S has been found present in several of the formations, so well completions capable of withstanding such conditions are of critical importance. This paper describes how the acquisition of WellCat™, Landmark's tubing stress analysis software program, and rigorous scrutiny of well completion components helped Saudi Aramco identify a significant number of mechanical weak links previously overlooked by an in-house computer program. The ability to analyze well completions in intricate detail, and model each frac stage with realistic fluid rheology, provided a powerful tool which helped identify weak links in need of removal to prevent potential problems.
A systematic approach to evaluate existing and planned well completions was implemented, close cooperation between several Saudi Aramco groups and Landmark established, specific modification recommendations issued, and an action plan to improve future completions and strengthen existing ones was put in motion.
Artificial Neural Networks Models for Identifying Flow Regimes and Predicting Liquid Holdup in Horizontal Multiphase Flow
Authors: Osman El-Sayed A. 
Published: December 2007

Abstract
Knowledge of liquid holdup and multiphase flow regimes in pipes is very important in pressure drop calculations and design of surface facilities. To predict the holdup, one has to define the flow regime at a given pressure, superficial gas and liquid velocities, temperature, and other flow characteristics. Several flow maps, regression and mechanistic models are available in literature to predict holdup and flow regime. However, some of these models do not predict the liquid holdup correctly.
This paper presents two Artificial Neural Networks (ANN) models to identify the flow regime and calculate the liquid holdup in horizontal multiphase flow. These models are developed using experimental data - 199 data points - and utilizing three-layer back propagation neural networks. Superficial gas and liquid velocities, pressure, temperature and fluid properties are used as inputs to the network. The output of the first network is the flow regime, while the other network predicts the liquid holdup. One-half of the data was used to train the ANN models, one quarter to cross-validate the relationships established during the training process and the remaining quarter to test the models and evaluate their accuracy. The results show that the developed models provide better predictions and higher accuracy than the empirical correlations developed specifically for these data groups. The developed flow regime model predicts the flow regime correctly for more than 97% of the data points. The liquid holdup model outperforms the published models in terms of the lowest absolute average percent error (9.407), the lowest standard deviation (8.544) and the highest correlation coefficient (0.9896).
Pre- Field Trial Testing of a Twin Screw Multiphase Pump
Authors: Yamashita M. , Sharma Y. , Ihara M. , Yamada K. 
Published: December 2007

Abstract
Performance tests were conducted on a twin screw multiphase pump in a large-scale flow loop prior to its first trial in an oil field in the Middle East. The main objectives of these tests were (1) confirmation of the pump’s hydrodynamic performance by examining the flow rate-head (Q–H) curves and the efficiency-head (η–H) plots, (2) checking the integrity of the design and construction, and (3) obtaining operational experience with the complete system. The pump was installed at the exit of a 82 m long, 106.3 mm ID pipeline and upstream of a three phase high pressure separator. The fluids used were nitrogen and water. A total of 76 flow tests were executed under the following experimental conditions; gas volume fraction (GVF) at the suction: 0 – 95 %; pump speed: 1200 – 1800 revolutions/minute; and differential pressure: 142 – 350 psig. These ranges covered most of the operating conditions to be expected during the field trial.
The pump operated successfully in the flow loop for a total of 150 hours. The Q-H curves showed an increase in volumetric efficiency with an increase in GVF. At high GVF, above 80%, an almost critical flow situation was attained, where the total flow rate was independent of the differential pressure. The η–H plots showed that the pump efficiency decreases with an increase in GVF. These characteristics are consistent with the results of tests conducted by other manufacturers on similar pumps. During the tests, no leaks were obtained through the mechanical seals and there were no problems with the quenching unit and cooling at the bearings. A maximum rise in temperature of 13 °C occurred when the GVF was 95%. Scratches seen on the external face of the screw and the internal face of the sleeve were attributed to scales in the pipeline. As a result of these data, the pre-field trial tests on the twin screw pump were considered successful and ready for testing in an oil field.
Quality Assurance Tool for PVT Simulator Predictions
Authors: Varotsis N. , Gaganis V. , Nighswander J. 
Published: December 2007

Abstract
The currently available PVT simulators predict the physical properties of reservoir fluids with varying degrees of accuracy depending on the type of the model utilised, the nature of the fluid and the prevailing conditions. Nevertheless, they all exhibit the significant drawback of lacking the ability to estimate the quality of their answers.
Artificial Neural Networks (ANNs), trained by large PVT databases, are increasingly utilized to provide accurate predictions of physical properties mainly due to their ability to learn from experience. The utilization of such models offers the unique capability of estimating the quality of their predictions as their degree of competence can be evaluated for each unknown test case1-2. The accuracy of the ANN based PVT simulators depends heavily on the density of the database compositional mapping around the coordinates of the unknown reservoir fluid. Unknown test cases found outside the available training space may lead to poor predictions.
In this work, a quality assurance tool is presented that is integrated to the ANN based PVT Expert™ model. This tool, for an unknown fluid, qualifies the predictions of the PVT simulator based on the evaluation of the affinity of the test case with the training data sets contained in the utilised database. Subsequently, the competence with which the ANN model has learned the general trend in the area around any new test case is assessed numerically.
This innovative approach was successfully tested against a large set of studies "unseen" by the PVT Expert. The ability of providing confidence for the accuracy of the PVT predictions and of assessing their quality, significantly upgrades the applicability of the PVT simulator as a valuable reservoir management tool.
Using an Artificial Neural Network to Develop a Wall-Loss Model for Coiled Tubing Fracturing Operations
Authors: Rispler Keith , McNichol Joanne , Matiasz Kevin , Rheinlander Mark 
Published: December 2007

Abstract
Coiled tubing (CT) erosion can occur during CT fracturing operations. Resulting wall loss and fatigue can limit CT life and prevent safe wellsite operations. An artificial neural network (ANN) has been successfully developed for accurately predicting wall loss resulting from erosion.
This paper presents a case history in which ANN technology was used to successfully manage tubing strings during CT fracturing operations. During these operations, wall loss affects CT pressure ratings, tensile strength, and fatigue, all of which are critical performance parameters used for determining CT life and identifying a safe operating envelope. An ANN can predict erosional wall loss and quantify critical performance parameters for specific applications.
Flow Equilibration Towards Horizontal Wells Using Downhole Valves
Authors: Sinha S. , Kumar R. , Vega L. , Jalali Y. 
Published: December 2007

Abstract
This paper analyzes the problem of heel coning under a variety of drive mechanisms and studies how deployment of downhole flow control devices along the length of the horizontal well affects this phenomenon. To reproduce the heel coning effect for homogeneous permeability fields, wellbore hydraulics must be taken into account. The control approach adopted in this work aims to achieve equal inflow from the heel and toe halves of the completion by adjusting the choke position in accordance with the in-situ flow rate. This strategy likens the behavior of the instrumented well to an infinite conductivity well, as far as inflow is concerned. The control strategy, however, has an outflow/lift cost, as it requires running stinger tubing inside the liner. For water-drive, this scheme results in delay of water breakthrough and extension of the pure oil production plateau. Alternatively, plateau production could be increased. For gas cap-drive, analogous conclusions hold except that the gas/oil ratio constraint necessitates a cycled production scheme with rate cutbacks for successive cycles. For the combined aquifer- and gas cap-drive, control mitigates gas coning more than water coning, because the well is positioned nearer the water-oil contact to satisfy the maximum recovery criterion within the operational constraints adopted in this study. Active control by downhole valves, therefore, is an effective means of overcoming the problem of heel coning where the displacing phase is water, gas, or both. Drainage becomes isotropically more uniform. In practice, realization of this scheme requires a fully coupled flow monitoring and control system.
Can Oil and Gas Companies Extend Best Operating Practices to Community Development Assistance Programs?
Authors: Wells John Bruce , Perish Meredith , Guimaraes Luiz 
Published: December 2007

Abstract
Faced with massive consolidations and unpredictable price swings, oil and gas companies increasingly turn to operational efficiency as the cornerstone of profitability, and many are adopting innovative cost reduction strategies. For example, in November 1999, BP Amoco engaged Pricewaterhouse Coopers for a $1.1 billion 10-year business process outsourcing agreement to manage the financial reporting, accounts payable and accounting responsibilities of its chemical, oil-exploration and production units.[1]
In one area, however, best practices remain the exception rather than the rule: community development programs.
Extractive industries in developing countries spend millions of dollars per year on community development programs in their areas of operation. For example, BP is soon to announce a global commitment to donate 1 percent of annual net revenues to social programs; while in Indonesia, P.T. Freeport donates 1 percent of annual gross revenues (US$ 16 million to US$19 million per year) to social programs in Irian Jaya. The authors estimate that global spending by oil, gas and mining companies on community development programs totals more than US$ 500 million per year.
While the goal of these development assistance programs is to better the communities in which the firms operate, the programs themselves are often designed and managed by operational staff whose backgrounds are in engineering and business rather than in community development.
As a result, corporate-funded community development programs do not often effectively serve either the firms or the communities.
Recently, some oil, gas and mining companies have begun to explore alternative approaches to community development. This paper assesses the traditional model and two emerging alternatives.
The Utilization of Malaysian Local Bentonite as an Extender and Free Water Controller in Oil-Well Cement Technology
Authors: Samsuri A. , Junin R. , Osman A. M. 
Published: December 2007

Abstract
This paper presents the results of experimental studies for Malaysian bentonite from Sabah (Lahad Datu and Tawau areas) application in oil- well cementing as compared to world wide commercially used Wyoming bentonite of USA. Samples were dried, grounded and sieved into particle size of 75(m. The experiments include XRD & XRF techniques to determine the chemical compositions and mineralogical contents of bentonite. Methylene blue tests were carried out to estimate the value of cation exchange capacity (CEC) in order to determine the approximate montmorillonite content. In the cement performance tests, class-G cement slurry mixed with bentonite in the range of 2%- 16% BWOC. The cement slurries were tested in accordance of API Specification 10. Dry and wet treatment processes were also conducted for the Malaysian bentonite to upgrade its performance.
From laboratory investigations, it showed that Malaysian bentonite has less content of montmorillonite mineral and more impurity materials such as quartz, kaolinite, illite, muscovite and hematite, while Wyoming bentonite considered as high- quality bentonite. Malaysian bentonite has low values of CEC which had been improved after treatment processes. Malaysian bentonite has low degree of swelling. The free water of the cement slurry increased with the increase of bentonite concentrations as compared to Wyoming bentonite. On the other hand, after treatment processes, the free water decreases in the cement slurry with bentonite concentrations increased. The Lahad Datu's bentonite had lowered slurry density after the treatments than the Tawau's bentonite.
Reservoir Management for Ultra-Thin Oil Columns Under Gas-Cap and Water Support: Attaka Field Examples
Authors: Vo D. T. , Witjaksana Renas S. , Sukerim Waryan , Dharmawan Agung , Iwan Harmawan , Okuno Masato 
Published: December 2007

Abstract
Exploitation of ultra-thin oil columns under gas cap and water support is challenging since both gas and water coning can seriously curtail oil recovery. Horizontal wells have shown to alleviate some of this problem as they allow for less drawdown and hence reduce coning for better recovery efficiency. Although the industry has shown horizontal drilling cost continues to be lowered, economics is still a major issue in exploiting ultra-thin oil bands using horizontal completion.
This paper presents a case study showing lessons learned from managing reservoirs with ultra-thin oil bands with less than 20 ft and sandwiched between gas cap and bottom/edge aquifer. Actual data from a field characterized by stacked pays of fluvial and deltaic channel sands in the Mahakam Delta complex are demonstrated. Subject to long-term production, the originally thick oil columns in these reservoirs have now become thinner, yet carry significant reserves to be prudently further developed. Issues involved in reservoir management such as well surveillance, well planning and prognosis, operating while drilling and producing, and long-term development plans are discussed. Reservoir modeling is shown to be the guide not only for well planning but also for well operations as it is used to select well type and completion strategy, optimize well production and prepare for continuous annual operating plan.
The vast well performance database provided from the paper shows horizontal drilling continues to be the main vehicle to develop these ultra-thin oil bands. Care however needs to be taken to scrutinize the economics inherent in selecting this type of completion, as other alternative methods also deserve to be considered.