bluuebunny/crossref_metadata_2025_split huggingface dataset:
Investigation of geophysical challenges in land seismic data acquisition in Nigeria: case study of parts of the Niger Delta region
Authors: Onwubuariri C. N. , Al-Naimi L. S. , Ijeh B. I. , Mgbeojedo T. I. , Igboekwe M. U. , Nnanna L. A. 
Published: December 2021

AbstractGeophysical analysis was carried out to evaluate the challenges encountered in land seismic exploration within the study area. This analysis cuts across various stages in land seismic acquisition. These stages include the following: the availability of the prospect map as originally planned by the prospect owners—the client, the desk study and planning of this map by the seismology section (planning seismologist) for acquisition convenience and the field implementation of the acquisition which the survey, drill and recording (preloading, shooting, swath move, line check, LAUX crew and recording platform) sections carried out. The challenges observed included environmental challenges, noise interference, weather conditions (statics or electrostatics interference), line break, faulty equipment, wrong detailing, cake or expired explosives, poor or compromised supervision, security and permit challenges. These challenges are peculiar to Nigeria due to inadequate implementation of policies that guide human settlements and activities. Nigeria is within the climate region where most at times it is very impossible to control natural events like cloudy weather, rainfall, thundering and lightening. As such, the problem of static charges interfering with acquired seismic data becomes inevitable, mostly during the rainy season. Almost total dependency on imported technology and lack of readily available experienced manpower also contribute to these challenges, most especially when it has to do with proper inspection of equipment and materials required for the acquisition and supervision processes. Approaches to follow to minimize the observed challenges were equally highlighted.
Improving hydraulic fracturing effectiveness in depleted and low-pressure reservoirs using N2-energized fluids
Authors: Elgibaly A. A. , Salem A. M. , Soliman Y. A. 
Published: December 2021

AbstractFoamed and energized fluids fracturing has been used in both conventional and unconventional reservoirs, as they reduce the amount of water used and hence minimize deleterious impact on water-sensitive formations. They also aid in the flow back after treatment in reservoirs where drawdown is limited. In this paper, the most important foam properties are presented, in addition, when to use energized fluids fracturing and how to choose the best energizing component with the best quality. The impact of N2-energized fluids fracturing (NEF) on wells that were previously fractured using conventional fracturing fluids is also presented. In addition, a comparison between the results of N2-energized fluids fractured and conventional fluid fractured wells is presented. The effect of using 20 to 50% (NEF) on production through surface well testing and live production data showed excellent and sustainable production rates. An economical study is presented through comparing the total capital cost of both NEF and conventional fluids fracturing, in addition to the hydrocarbon recovery of wells after both types. Data considered in this work represent about 40 wells fractured using NEF in the Egyptian Western Desert.
Numerical modeling and experimental investigation on the effect of low-salinity water flooding for enhanced oil recovery in carbonate reservoirs
Authors: Hosseini Erfan , Sarmadivaleh Mohammad , Mohammadnazar Dana 
Published: December 2021

AbstractNumerous studies concluded that water injection with modified ionic content/salinity in sandstones would enhance the oil recovery factor due to some mechanisms. However, the effects of smart water on carbonated formations are still indeterminate due to a lack of experimental investigations and researches. This study investigates the effects of low-salinity (Low Sal) solutions and its ionic content on interfacial tension (IFT) reduction in one of the southwestern Iranian carbonated reservoirs. A set of organized tests are designed and performed to find each ion’s effects and total dissolved solids (TDS) on the candidate carbonated reservoir. A sequence of wettability and IFT (at reservoir temperature) tests are performed to observe the effects of controlling ions (sulfate, magnesium, calcium, and sodium) and different salinities on the main mechanisms (i.e., wettability alteration and IFT reduction). All IFT tests are performed at reservoir temperature (198 °F) to minimize the difference between reservoir and laboratory-observed alterations. In this paper, the effects of four different ions (SO42-, Ca2+, Mg2+, Na+) and total salinity TDS (40,000, 20,000, 5000 ppm) are investigated. From all obtained results, the best two conditions are applied in core flooding tests to obtain the relative permeability alterations using unsteady-state methods and Cydarex software. The final part is the simulation of the whole process using the Schlumberger Eclipse black oil simulator (E100, Ver. 2010) on the candidate reservoir sector. To conclude, at Low Sal (i.e., 5000 ppm), the sulfate ion increases sulfate concentration lower IFT, while in higher salinities, increasing sulfate ion increases IFT. Also, increasing calcium concentration at high TDS (i.e., 40,000 ppm) decreases the amount of wettability alteration. In comparison, in lower TDS values (20,000 and 5000 ppm), calcium shows a positive effect, and its concentration enhanced the alteration process. Using Low Sal solutions at water cut equal or below 10% lowers recovery rate during simulations while lowering the ultimate recovery of less than 5%.
Waterflood optimization using an injector producer pair recovery factor, a novel approach
Authors: Alizadeh Nasser , Salek Ben 
Published: December 2021

AbstractThis paper presents an approach to optimize the recovery factor and sweep efficiency in a waterflooding process by automating the optimum injection rate calculations for water injectors using streamline simulation. A streamline simulator is an appropriate tool for modern waterflood management and can be used to determine the dynamic interaction between injector and producer pairs, which will vary over time based on sweep efficiency and operational changes. A streamline simulator can be used to identify injectors, which are not supporting production and contributing mainly to water producing wells. Streamlines illustrate natural fluid-flow paths in the reservoir, which are based on fluid properties, rock properties, well distribution and well rates across the reservoir. A bundle of connected streamlines can provide the oil in place between an injector/producer pair at any given time during a simulation run. Thus, the well pair recovery factors for each injector/producer pair, the produced water cut and the weighting factor for each injector are determined. Multiplying this weighting factor by the injection rates determines the new injection rate for each injector. For a well pair water cut that is lower than the average field water cut, the injection rate will be increased and vice versa. Given a finite volume of injection water, there will be a re-allocating of water from a well pair with a low recovery factor and high water cut and redistributing the water to injectors supporting low water cut producers, thus maximizing the recovery factor and reducing the field water production. The described approach is an automated procedure during the reservoir simulation run, making it appropriate for full field waterflood optimization with many injectors and producers in high-resolution heterogeneous brown reservoirs. This approach can reduce the water cut and increase the recovery factor and extend the life of the waterflooded oil fields. It was initially tested with a synthetic model and later with an actual reservoir model, which will be described in this paper.
Dynamic effects of fault modeling on stair-step and corner-point grids
Authors: Alpak Faruk O. , Chen Tianhong 
Published: December 2021

AbstractFault modeling has become an integral element of reservoir simulation for structurally complex reservoirs. Modeling of faults in general has major implications for the simulation grid. In turn, the grid quality control is very important in order to attain accurate simulation results. We investigate the dynamic effects of using stair-step grid (SSG) and corner-point grid (CPG) approaches for fault modeling from the perspective of dynamic reservoir performance forecasting. We have performed a number of grid convergence and grid-type sensitivity studies for a variety of simple, yet intuitive faulted flow simulation problems with gradually increasing complexity. We have also explored the added value of the multipoint flux approximation (MPFA) method over the conventional two-point flux approximation (TPFA) to increase the accuracy of reservoir simulation results obtained on CPGs. Effects of fault seal modeling on grid-resolution convergence and grid-type sensitivity have also been briefly examined. For simple geometries, both SSG and CPG can be used for fault modeling with similar accuracy in conjunction with the pillar-grid approach. This is evidenced by the fact that simulation results from SSG and CPG converge to identical solutions. SSG and CPG yield different results for more complex geometries. Simulation results approach to a converged solution for relatively fine SSGs. However, a SSG only provides an approximation to the fault geometry and reservoir volumes when the grid is coarse. On the other hand, non-orthogonality errors are increasingly evident in relatively more complex faulted models on CPGs and such errors cannot be addressed by grid refinement. It has been observed that MPFA partially addresses the discretization errors on non-orthogonal grids but only from the total flux accuracy perspective. However, transport related errors are still evident. Grid convergence behaviors and grid effects are quite similar with or without fault seal modeling (i.e., dedicated fault-zone modeling by use of scaled-up seal factors) for simple geometries. However, in more complex test cases, we have observed that it is more difficult to achieve converged results in conjunction with fault seal modeling due to increased heterogeneity of the underlying problem.
Simulation of two-phase flow by injecting water and surfactant into porous media containing oil and investigation of trapped oil areas
Authors: Sajadi Seyed Mousa , Jamshidi Saeid , Kamalipoor Meisam 
Published: December 2021

AbstractNowadays, as the oil reservoirs reaching their half-life, using enhanced oil recovery methods is more necessary and more common. Simulations are the synthetic process of real systems. In this study, simulation of water and surfactant injection into a porous media containing oil (two-phase) was performed using the computational fluid dynamics method on the image of a real micro-model. Also, the selected anionic surfactant is sodium dodecyl sulfate, which is more effective in sand reservoirs. The effect of using surfactant depends on its concentration. This dependence on concentration in using injection compounds is referred to as critical micelle concentration (CMC). In this study, an injection concentration (inlet boundary) of 1000 ppm was considered as a concentration less than the CMC point (2365 ppm). This range of surfactant concentrations after 4.5 ms increased the porous media recovery factor by 2.21%. Surfactant injection results showed the wettability alteration and IFT finally increases the recovery factor in comparison with water injection. Also, in wide channels, saturation front, and narrow channels, the concentration front has a great effect on the main flowing.
The effect of chemically enhanced oil recovery on thin oil rim reservoirs
Authors: Olabode O. A. , Ogbebor V. O. , Onyeka E. O. , Felix B. C. 
Published: December 2021

AbstractOil rim reservoirs are characterised with a small thickness relative to their overlying gas caps and underlying aquifers and the development these reservoirs are planned very carefully in order to avoid gas and water coning and maximise oil production. Studies have shown low oil recoveries from water and gas injection, and while foam and water alternating gas injections resulted in positive recoveries, it is viewed that an option of an application of chemical enhanced oil recovery option would be preferable. This paper focuses on the application of chemical enhanced oil recovery to improve production from an oil rim reservoir in Niger Delta. Using Eclipse black oil simulator, the effects of surfactant concentration and injection time and surfactant alternating gas are studied on overall oil recovery. Surfactant injections at start and middle of production resulted in a 3.7 MMstb and 3.6 MMstb at surfactant concentration of 1% vol, respectively. This amounted to a 6.6% and 6.5% increment over the base case of no injection. A case study of surfactant alternating gas at the middle of production gave an oil recovery estimate of 10.7%.
Dynamics of hydrocarbon production in long-developed fields of the South Caspian basin with emphasis on reserves renewability
Authors: Feyzullayev A. A. , Lerche I. , Mamedova I. M. , Gojayev A. G. 
Published: December 2021

AbstractThe scientific basis of the paper is the concept of renewability of oil and gas resources. In accordance with this concept, the purpose of this paper is to estimate the volumetric rate of natural replenishment of the reservoir with oil and gas using the example of long-developed Bibieybat oil and Garadag gas condensate fields in the South Caspian Basin (SCB). The methodological approach of this assessment is based on the authors' assumption that at the late stage of field development, the recoverable amount of hydrocarbon fluids is compensated by the amount of their natural inflow, as a result of which oil or gas production stabilizes. The analysis of the dynamics of hydrocarbon production for the Bibieybat oil field covered the period from 1935 to 2018, and for the Garadag gas condensate field from 1955 to 1979. The rate of natural oil replenishment calculated for 29 operating facilities of the Bibieybat field varies per well within 0.32–1.4 ton/day (averaging 0.76 ton/day) or about 277 ton/year. The rate of natural gas inflow at the Garadag gas condensate field is about 5.2 thousand m3/day per well.
Implementation of a novel eccentric dog leg reamer in oil well drilling
Authors: Shokry Amir , Elgibaly Ahmed , Salem Adel 
Published: December 2021

AbstractA high-quality wellbore is generally considered to have a gauge hole, a smooth wellbore and a wellbore with minimum tortuosity. Therefore, dog leg reamers (DLRs) have been recently proposed and implemented to specifically provide a high-quality wellbore which in turn improves the overall drilling performance. These improvements include smoothening the wellbore from high in place dogleg, lowering drag values, improving the tripping performance, increasing the success ratio of wireline logging tools to reach total depths and enhancing the casing and cement jobs. DLRs are an eccentric string reamers which have been recently designed and optimized using modelling software, and a mathematical model has been deduced to specify the weight and torque distribution between the bit and DLR based on mechanical specific energies at bit and DLR with a model accuracy closely matches the field data. A total of twenty five runs all over the world have been performed to date in hole sizes ranging from 12¼″ to 6″. Directional work has also been performed showing good directional control with this system, and no vibration issues have been reported. The development of this down hole tool has added new capability to the industry in the optimization of hole enlargement applications. The benefit is realized in a reduced number of days required to drill the well and in reduced total well cost. In addition, getting casing into the hole sooner reduces the accompanying risks and can contribute to reducing operational nonproductive time. Several case studies from three fields X, Y and Z from Egypt, Oman and Saudi Arabia, respectively, will be discussed to demonstrate the positive economic impact of deploying DLR in not only the deviated holes but also in vertical wells.
Borehole enlargement rate as a measure of borehole instability in hydrate reservoir and its relationship with drilling mud density
Authors: Li Qingchao , Liu Lingling , Yu Baohai , Guo Linian , Shi Sheng , Miao Linchun 
Published: December 2021

AbstractBorehole collapse will pose a threat to the safety of equipment and personnel during drilling operation. In this paper, a finite element multi-field coupling model for investigating borehole collapse in hydrate reservoir was developed. In this model, fluid seepage, heat transfer, hydrate dissociation and borehole deformation are all considered. Based on which, effects of drilling fluid density on both of hydrate dissociation and borehole collapse are investigated. The investigation results show that disturbance of drilling fluid invasion to hydrate reservoir will lead to hydrate dissociation around wellbore, and dissociation range narrows obviously with the increase in drilling fluid density. When the relative fluid density is 0.98, natural gas hydrates in reservoir with a width of about 16.65 cm around wellbore dissociate completely. However, dissociation range of natural gas hydrate has decreased to 12.08 cm when the relative fluid density is 1.10. Moreover, hydrate dissociation around wellbore caused by drilling fluid invasion may lead to borehole collapse, and borehole collapse can be significantly restrained with the increase in relative fluid density. Borehole enlargement rate is 33.67% when the relative fluid density is 0.98, but nearly no collapse area displays around wellbore when the relative fluid density increases to 1.12. In addition, investigation herein can provide an idea for designing drilling fluid density in hydrate reservoir when different allowable borehole enlargement rate is considered. The minimum fluid density designed for avoiding disastrous borehole collapse increases nonlinearly when higher requirements for borehole stability are proposed.
A novel artificial intelligence automatic detection framework to increase reliability of PLT gas bubble sensing
Authors: Katterbauer Klemens , Marsala Alberto F. , Schoepf Virginie , Donzier Eric 
Published: December 2021

AbstractProduction logging tools (PLTs) and formation testing, even in logging while drilling (LWD) conditions during underbalanced drilling, are key technologies for assessing the productivity potential of a gas well and therefore to maximize recovery. Gas bubble detection sensors are key components in determining the fluid phases in the reservoir and accurately quantify recoverable reserves, optimize well placement, geosteering and to qualify the production ability of the well. We present here a new nonlinear autoregressive - breakdown artificial intelligence (AI) detection framework for PLT gas bubble detection sensors that categorize in real-time whether and which sensors become unreliable or have broken down during the logging measurements. AI tools allow the automatization of this method that is critical during data quality control of post-drilling PLT, but it is essential when the measurements are performed in LWD as data assessment and processing need to occur in real-time. This AI framework was validated on both a training and testing dataset, and exhibited strong classification performance. This method enables accurate real-time breakdown detection for gas bubble detection sensors.
A review on current trends and prospects in the pyrolysis of heavy oils
Authors: Ore Odunayo T. , Adebiyi Festus M. 
Published: December 2021

AbstractIncreasing global demand for energy is an aftermath of an upsurge in world population and industrialization. The exploration of heavy oils such as oil sands, tight oils, and heavy oils, is thus becoming a necessity in a bid to alleviating the energy crisis. The processing of fossil fuels using conventional methods is known to have devastating effects on global warming and ocean acidification. This has brought about innovation and development of environmental-friendly processing technologies. Of these processing technologies available to date, pyrolysis is the most widely employed due to low operating complexity and economic cost. As revealed by the reviewed studies, the distribution of products formed during pyrolytic processes is a function of residence time, heating rate, the temperature of reaction, and reactor design. The latter significantly influenced the qualitative and quantitative yield of products formed during pyrolysis. Operating conditions of temperature, pressure, and catalyst are also influential factors in determining the product yields. Most research efforts in the last 30 years have identified that optimum production of pyrolytic oils occurred between thermal cracking temperature of 350 °C and 500 °C. The plausible mechanisms of pyrolysis are the free radical chain mechanism involving the homolytic cleavage of the C–C bond, and the electron transfer mechanism. This review pointed out the current status of the adoption of pyrolysis by petroleum and petrochemical industries as a processing technology for low-value heavy oils into high-value light fractions. The findings of the studies reviewed can help for better understanding of the optimum pyrolysis conditions required for maximum production of oils and gases. It will also help in carefully choosing the most sustainable approach in a bid to averting economic and environmental risks.