bluuebunny/crossref_metadata_2025_split huggingface dataset:
Prospects and Economics of Miscible -CO2 Enhanced Oil Recovery in Some Nigerian Reservoirs.
Authors: Ibukunoluwa A. O. , Onyekonwu M. O. 
Published: February 2011

Abstract
On exhausting conventional oil extraction techniques, about 2/3 of discovered reserves are usually unproduced. CO2 injection into oil reservoirs is widely accepted as an effective Enhanced Oil Recovery (EOR) technique, and has been used in the oil industry for over 40 years. In this study, incremental oil, producible by CO2-EOR from the large domestic oil reservoirs at Obagi field was calculated. The study utilized the CO2-PROPHET model to evaluate the oil database and found Obagi fit for CO2 flooding. Afterwards a Kinder Morgan Scoping economic model was used to evaluate the economic viability of the flood. With 1.2 Billion barrels initial oil in place and a residual oil saturation of 50%, the field would only have up to 17% recovery at a 100% hydrocarbon pore volume of CO2 injected. Sensitivity on the Dykstra Parsons correlation coefficient showed that increasing the parameter i.e. (increasing heterogeneity) results in no change in oil produced with time. Also, a sensitivity on viscosity showed that for the range of oil viscosities analyzed, oil production clearly decreases with increasing oil viscosity. Economic sensitivity was positive with a Present Value Profit after Tax of $149.8MM. This is equivalent to $1,623,038,950.00 after a project lifetime of 25 years.
Non-Linear Programming for Well Spacing Optimization of Oil Reservoirs.
Authors: John U. M. , Onyekonwu M. O. 
Published: February 2011

Abstract
Background: The subject of well spacing is one of vital importance in the petroleum industry. The well itself plays a very significant role in the development of the oil and gas reservoirs and in the control of the recovery process. However, determination of appropriate well spacing for maximum economic oil recovery has been a complicated and controversial issue in oil field development. Various studies on the subject have indicated a slim relation between well spacing and recovery. This study will however focus on the optimization of field development in order to maximize returns on investment. A simplified economic optimization model to optimize well spacing in oil reservoirs has thus been proposed.
Methodology: The optimization model developed has been solved to find the optimal well spacing that will maximize Net Present Value of investment, using NonLinear Programming (NLP) Excel-Based Solver.Data for case study was from an offshore field. Sensitivity analysis to determine the extent of changes in optimum Well spacing with respect to model parameters was carried out.
Results: Cost of field development could be greatly optimized using NLP. Well spacing has been seen to decrease with recoverable reserves for maximum Net Present Value (NPV) until a point where increase in the number of wells decreases NPV. An optimal solution exits within this region. Optimal well spacing has been observed to be far more sensitive to oil price than to other model parameters such as investment cost per well, production rate and interest rate.
Conclusion: Intuitive approach to solving well spacing problem requires current oil industry knowledge and experience. Economics sets the limit for drilling of development and infill wells.
Controlling Fugitive Emissions in Nigeria's Oil and Gas Industry: Proper Sealing Device Selection a Panacea
Authors: Nwaoha Chikezie 
Published: February 2011

Abstract
As the world grows and economies develop, future demand for energy will continue to grow dramatically. The International Energy Agency and many others predict that the world's total energy demand will grow by 35% in 2030 higher than it is today, and oil/natural gas are expected to account for nearly 60% of total energy through 2030 (Glass J.S. jr., 2009). This implies that fugitive emissions must be minimized in order to preserve scarce resources and address the global climate challenge. Because of the predicted growth in emissions in the coming decades, 70 – 80% will come in developing countries (T Arrowsmith,2009). Nigeria a developing country, and the world'seleventh largest crudeoil producer with reserves estimated at over 36 billion barrels, will play a big role in preserving health, safety and global environment. Worldwide, fugitive emissions from equipment leaks such as valves, and pumps contribute to over 1 million metric tonnes of volatile organic compounds/hazardous air pollutants (VOC/HAP) per year (Onat A, 2006).
Pumps/compressors account for 10%, flanges-5%, tanks-10%, valves-60%, and relief valves-15% (Fluid Sealing Association, 2008). Valves which account for 60% of fugitive emissions presents the greatest opportunity for reducing fugitive emissions. Therefore, sealing devices will play a major role in lowering emissions. In this role they keep valves from releasing emissions, flanges from spraying fluids etc. The process of selecting the right sealing device begins with identifying service conditions. A simple acronym, TAMPSS-temperature, application, media, pressure, size and speed provides a general guide to assuring selection of the correct sealing device for your application (Drago J and Tones M, 2007). Therefore, this paper is aimed at presenting the most effective and efficient way of prolonging our scarce resources, reducing fugitive emissions, minimizing environmental harm, improving worker and public safety, and meeting the global energy demand.
Prediction of Vapor Pressure of Aqueous Hydrate Inhibitor Solutions Using Arrhenius-Type Asymptotic Exponential Function
Authors: Bahadori A. , Vuthaluru H. B. 
Published: February 2011

Abstract
Hydrate inhibition with different inhibitors such as, methanol, ethylene glycol (EG), continues to play a critical role in many natural gas transmission and processing operations. In this work, simple-to-use predictive tools are presented here for the prediction of vapor pressures of aqueous hydrate inhibitors (namely methanol, ethylene glycol, diethylene glycol and triethylene glycol) as a function of temperature and hydrate inhibitor mass fraction in water phase using a novel and simple-to-use Arrhenius-type asymptotic exponential function. The proposed tool predicts the vapor pressure of aqueous methanol solutions and glycol solutions for temperatures up to 100°C. Estimations are found to be in excellent agreement with the reliable data in the literature with average absolute deviations being around 3.8 and 1.5% for vapor pressures of aqueous methanol solutions and glycol solutions respectively. The proposed method is easier than currently available models and involves a fewer number of parameters, requiring less complicated and shorter computations. The tool developed in this study can be of immense practical value for the engineers and scientists to have a quick check on the vapor pressures of aqueous methanol, ethylene glycol, diethylene glycol, and triethylene glycol solutions at various conditions without opting for any experimental measurements. In particular, chemical and process engineers would find the approach to be user-friendly with transparent calculations involving no complex expressions.
Experiment and Mechanism Analysis on Threshold Pressure Gradient with Different Fluids
Authors: Baoquan Zeng , Linsong Cheng , fei Hao 
Published: February 2011

Abstract
Fluids with different components were used in threshold pressure gradient (TPG) experiment by steady "pressure~velocity" method. Influence of Permeability and fluids components on TPG was analyzed. The study indicates different fluids give different TPG versus permeability power function, TPG of different fluids was as follows: Distilled water &gt;Injected water &gt;Formation water &gt;Surfactant solution. Mechanism analysis of TPG reduction shows that higher salinity and Surfactant are favorable to TPG reduction, and it offers a theoretical explanation for injection of formation water and surfactant solution in the low permeability reservoir. The injection of the two fluids can decrease injection pressure and increase injection capacity for water wells.
Surfactant Treatment has Amazingly Improved Squeeze Cementing Result
Authors: Winarga Kanuga , Dewanto Christianto Widi 
Published: February 2011

Abstract
Usually squeeze cementing job was done in more than once; failure usually happens and need to be re-squeezed once or more. One time squeeze cementing is very rarely occurs. Hypothetical theory is caused by leaking, space appears between matrix rock and cement during drying process. This phenomenon happens due to the fluid base differentiation between both fluids in cementation process which causing dis-joint cement fluid (water base) with oil film that coats the rock matrix wall (oil wet).
Surfactant treatment method is used to reduce squeeze cementing frequency where main function of surfactant is to change fluid surface tension between oil and water so both fluids will blend homogeneously. Cement slurry as water base fluid are expected to perfectly coat in rock matrix that have changed to be water wet from originally oil wet. By injecting amount of surfactant into rock formation and soaking couple hours before squeeze cementing job execute, expected could change formation rock wettability from oil wet into water wet so coated and trapped oil between matrix rock will release and pushed by water or cement slurry when it pumped or squeezed. Perfectly adhere between rock matrix and cement will happen to disappear the space and finally increase the quality of Squeeze Cementing Job.
This study has applied in melibur wells; the result successfully reduces the cementing job frequency into half from the four times previously in each well. It leads the cost efficiency. The three wells that have been squeezed without surfactant hold the pressure test after four times cementing. Meanwhile from another two wells with surfactant treatment the frequency could be reduced and significantly saving cost about 41% from the previous. It was concluded that surfactant treatment has become a great solution to increase squeeze cementing quality.
Permeability Prediction of Un-Cored Intervals Using New IMLR Method and Artificial Neural Networks: A Case Study of Bangestan Field, Iran
Authors: Naeeni Mohammad Nazari , Zargari Hadi , Ashena Rahim , Ashena Rahman , Kharrat Riyaz 
Published: February 2011

Abstract
Knowledge of permeability is critical for developing an effective reservoir description. Permeability data may calculated from well tests, cores and logs. Normally, using well log data to derive estimates of permeability is the lowest cost method. In the last years, the concept of hydraulic flow units (HFU) has been used in the petroleum industry to improve prediction of permeability in un-cored intervals/wells. This concept is strongly related to the flow zone indicator (FZI) which is a function of the reservoir quality index (RQI). Both measures are based on porosity and permeability of cores. It is assumed that samples with similar FZI values belong to the same HFU.
This paper will focus on the evaluation of formation permeability in un-cored intervals for a carbonate reservoir in Iran from core and well log data. We used Flow Zone Index method for rock type identification and Artificial Neural Networks for permeability estimation. Identifying the hydraulic flow units that is the first step of predicting permeability always takes lots of time and lack appropriate accuracy. We have developed a new clustering technique that is more precise, easy to apply and taking much less time.
An Artificial Neural Network Approach to Formation Damage Prediction Due to Asphaltene Deposition
Authors: Rezaian A. , Kordestany A. , Haghighat Sefat M. 
Published: February 2011

Abstract
Formation damage due to asphaltene deposition could have bad consequences on oil production through heavy oil recovery, miscible flooding, and even primary recovery. Many tests were carried out by researchers to find the amount of permeability decline, but the limits in which the asphaltene deposited in oil or at the pore surface was not determined.
In this paper, neural network is used to predict rock-fluid interactions describing permeability decline due to asphaltene deposition. The second stage of asphaltene deposition (if we separate it into precipitation from liquid phase, and deposition on pore surface) is considered in which n-hexane is used to flocculate asphaltene particles in order to determine the effect of deposition on sandstone rock due to changing of pressure, temperature, and composition of reservoir oil.
An artificial neural network is trained using data gathered by performing various dynamic experiments with pre-separated oil asphaltene content, moreover, some of the experimental data used to test the network and resulted a good agreement so it could predict the trend of permeability reduction due to deposition of asphaltene.
This network can be used to predict the trend of formation damage due to asphaltene deposition under various pressures and asphaltene concentrations. Thus, this study guides us to a novel explanation of flow behavior in porous media.
Determination of Cone Receding Time in Horizontal Wells
Authors: Ibelegbu C. , Onyekonwu M. , Okorie C. 
Published: February 2011

Abstract
Often critical rates are never economical to operators as they seek to produce above the established critical rates without any prior analysis of an economical stand-off rate at which continuous high GOR/ BS&W becomes uneconomical. Wells are shut for long time without any knowledge of shut-in duration to allow for fluid stability before being brought back on production.
This study generates two new solutions, analytical and numerical solutions used in determining cone receding time in horizontal wells after coning occurs. Field data are used to validate the analytical and numerical solution results for the coned wells. Semi-analytical solutions are applied with the numerical solution results, to generate unique solution/ coefficient (Cth- cone coefficient) for each well/ reservoir with respect to its flow mechanisms associated with water coning/ production. An eclipse dynamic model is also used to validate the numerical results/ solutions.
Bonny NAG Well and Reservoir Surveillance Improvement
Authors: Gardiner D. C. , Sadiq S. O. , Temisanren T. , Ukauku I. , Amos T. 
Published: February 2011

Abstract
In 2008 Well and Reservoir Management was recognised by SPDC as a key improvement area to arrest field declines and to maximise production and recovery from existing assets. One of the focus assets was Bonny Non Associate Gas (BNAG) field. The Bonny NAG field supplies Non Associated Gas to the Nigeria Liquefied Natural Gas (NLNG) plant, forming a key component of SPDC's supply to Trains 1 to 5 (450MMscf/d).
This paper describes how acquiring downhole pressure data and re-establishing proper well and reservoir management practice in Bonny field lead to improvements in non-associated gas production and reserves and reduction in uncertainty of predicted field performance for Bonny NAG.
After overcoming a number of challenges, a downhole data gathering programme for the Bonny NAG reservoir (one MRT and three static surveys) was successfully completed in October 2008, the first subsurface data acquired since 2005. The data obtained were analysed & interpreted and the result incorporated into an integrated reservoir, well, surface network modelling and optimisation system - "IPSM" to predict: (1) reservoir dynamics, wells potentials and performance; (2) identify surface network bottlenecks; and (3) gas deliverability forecast to NLNG.
Results of pressure transient analysis and material balance model in the IPSM indicated that the aquifer was much stronger than previously estimated from early pressure and production (data when less than 10% of GIIP had been produced). This led to a revision of the field's production strategy. Bonny NAG offtake, which had previously been restricted, was immediately increased by 25MMscf/d (maximum possible within surface facilities constraint) to accelerate and maximize production before water breakthrough occurs. Reserves figures were also re-assessed resulting in an increase in reserves booking in 2009. Also, a 14" transfer line was identified from surface network optimization efforts as the major bottleneck in the BNAG surface facility. Various options were considered to improve facility throughput. The result was a quick win project to engineer and install a 4" crossover line from the fuel gas plant to the BNAG facility. Work on the 4" crossover line started in February 2009 and was successfully completed and commissioned in October 2009, delivering an additional 14MMscf/d of sales gas from the BNAG plant to NLNG.
Development of Environmentally Friendly Oil Based Mud using Palm- Oil and Groundnut-Oil
Authors: Adewale Dosunmu , Ogunrinde Joshua. O 
Published: February 2011

Abstract
The development of an oil-based mud from palm oil and ground-nut oil was carried out in this work. It also compares the eco-toxicological properties of conventional base oil of diesel and vegetable oils derived from palm oil and groundnut oil.
A drilling mud was formulated with both palm oil and groundnut oil and standard additives were added. Complete mud check was conducted on the mud in order to determine the rheological properties. Toxicity of diesel, palm oil and groundnut oil were compared by exposing corns planted on humus soil beds prepared with palm. Also, groundnut oil-based mud with an oil/water ratio of 90/10 was formulated successfully. When the humus beds planted with corn were exposed to diesel, palm oil and groundnut oil, the corn exposed to diesel lost its greenness and died while that exposed to palm oil and groundnut oil retain its greenness. Palm oil-based mud having 90/10 oil/water ratio and groundnut oil-based mud exhibited a 20% and 12% average rate of growth without losing all its greenness.
Palm oil based mud formulated with different oil/water ratios congealed during the course of formulation. They exhibited high viscosity and progressive gel characteristics.
In conclusion, oil based mud developed using Palm oil and groundnut oil should be encouraged since its highly biodegradable, have better eco-toxicological properties and the cost of treatment of the cuttings are lower compared to Oil-based drilling mud formulated with diesel, mineral and conventional synthetic oil. They can also be a source of income to the farmers producing the palm oil in large quantity and help in the growth of the Nigerian economy since we can supply the palm oil to oil and gas companies that need it to produce their mud for drilling operations. In addition to these benefits, the oil based mud formulated with palm oil and groundnut oil is also functionally as efficient as the ones formulated with diesel and conventional synthetic oils.
A Proposed Cone Breakthrough Time Model for Horizontal Wells in Thin Oil Rim Reservoirs
Authors: Omeke J. E. , Livinus A. , Uche I. N. , Obah Boniface , Ekeoma E. 
Published: February 2011

Abstract
Understanding oil rim reservoir production dynamics is critical to successful development of thin oil rims. The interplay of subsurface factors and production constraints determine the dynamics of oil Rim reservoir production. Therefore in this study the impact of a range of sub-surface uncertainty on oil rim recovery was captured by employing the Plackett-Burman Design of Experiment (DOE) technique. The methodology involves a detailed generic oil rim simulation study. By employing the classical numerical reservoir simulation equation, assuming a negligible difference in fluid potential and applying material balance principle, the response surface model or proxy developed for cumulative oil recovery (Np) was combined with the cone breakthrough time equation and forms an integral part of the model. The model was developed for a thin oil column, between 20ft-60ft, sandwiched between a gas cap and aquifer.
The results from the model were compared with that gotten from a simulation study which gave reasonable value of cone breakthrough time with its equivalent water cut value.
The applicability of the model was tested by predicting the water breakthrough time for some selected major oil rim reservoir with gas cap and Aquifer in Niger-Delta.
The proposed model is reliable based on the fact that it captured some major sub-surface uncertainties (11 sub-surface parameters) that influences coning results while most pre-existing model do not. It can as well serve as a quick predictive tool before embarking on detailed reservoir simulation.
Investigation of Effect of Gas Injection Pressure on Oil Recovery Accompanying CO2 Increasing in Injection Gas Composition
Authors: Abbasi Saeed , Tavakkolian Mohsen , Shahrabadi Abbas 
Published: February 2011

Abstract
Gas injection is a common EOR method for increasing oil recovery factor. It is an economical method, especially in cases where the injection gas for such gas injection project is easily available.
In this study, the performance of gas injection into one of the Iranian reservoirs is investigated. Three sets of core flood experiments were conducted. Each run was conducted at different composition and injection pressure. The results of experiments revealed the fact that the recovery efficiency depends strongly on the injection pressure. It should also be noted that gas enrichment using components leading miscibility could increase the recovery. The optimum enrichment level was also an affecting factor, which controls the overall efficiency of gas injection.
In the last phase of this study, the minimum miscibility pressure of the injected gas and in-situ oil under operated conditions was calculated using simulation package. These simulation runs were conducted for different percentage of CO2 in injected gas. Results of these simulation runs were in a good agreement with experimental results. It was found that as the CO2 contents of the injected gas increased the minimum miscibility pressure (MMP) decreased. Displacing agent has a stronger effect in high pressures. It means that partial miscibility supplied by pressure buildup would lead to increasing recovery factor.
Comparison and Limitation Analysis of Approaches for Porosity Evaluation from NMR and Three Porosity Logs in Low Permeability Gas Sands with Bad Borehole
Authors: Wen Tang , Rui Xu , Ling-Ling Zhi , Xiao-Gang Wang 
Published: February 2011

Abstract
In this paper, we compare four methods of calculating reservoir porosity in low permeability gas sandstones with bad borehole condition, they are neutron-density crossplot technology, DMR technology, piecewise scale methods from acoustic time logging and SMR technology. The principle and limitation of these methods are analysised. When the borehole condition is good, these four technologies are all available, but in the wells with bad borehole, the technology of calculating reservoir porosity by integrating interval transit time logging and NMR logging, the neutron-density crossplot are recommended. For the NMR data acquired from CMR tool, the NMR porosity must be calibrated from deep lateral resistivity or deep induction resistivity logging, but these technologies are still the most useful because the computation process are simple and the odd error is less than DMR technology. The piecewise scale methods is also not recommended because it will spend too much time for log analysts.