Petroleum Research Journal is a refereed scientific journal issued periodically to publish innovative and previously unpublished research in various fields of applied and theoretical scientific disciplines that fall within the objectives of the Petroleum Research Centre and the oil and gas sector.
Triassic and Creataceouse Palynomorphose from WellA2-045 /01 Offshore Libya
iassic and Cretaceous palynomorphs have been recovered from twenty three ditch cutting samples of borehole A2-054/01 located in the most northern part of Sirt Basin (Offshore), Libya. Microscope investigations revealed moderately rich assemblages consisting only miospores in the Triassic section and mixed palynomorphs (dinocysts, miospores & algae) in the Cretaceous section. The recovered palynomorphose from the studied samples enabled to erect two distinctive palynological assemblages. These assemblages range from Early Triassic to Early Cretaceous in age. The ages assigned to these assemblages have been determined by comparing the palynomorphs assemblages with similar assemblages recorded from Mesozoic sequences in other nearby regions in Africa, North America and Europe. Paleoenvironmental interpretation of the investigated sediments revelled that Cretaceous sediments were mostly deposited in shallow marine environment; other investigated rocks (Triassic) were deposited either in non-marine environment or in marginal marine environment
Copyright (c) 2016 PRC Petroleum Research Journal
TQM Implementation in Libyan Oil and Gas Sector
This paper investigates quality factors that are absolutely essential for successful implementation Total Quality Management (TQM) in Libyan oil and gas companies (LOGCs). Eleven quality factors with forty-two elements where identified based on literature search to develop a questionnaire to carry out the survey in order to identify the quality factors that are seen by LOGCs to be critical to the success of TQM implementation. Forty-five questionnaires were provided by hand to quality-related managers from the Libyan Oil and Gas sector. A total of forty-two were returned sufficiently completed, that gave us a response rate of approximately 93.33%. The empirical analysis demonstrates several key findings: The analysis indicated that twenty-four quality factors are found to be critical and absolutely essential for successful TQM implementation. These factors classify into three levels of criticality. All of the factors were found to be supported by similar studies and cited literatures. These factors will direct an organisation towards business excellence and enhancing success of TQM practices in the oil and gas sector
Tidal Influnced Eocene Deposits of Dur At Talah (Libya) Compared with Present DayTidal Sediments from the Bay of MT St Michel (France)
Dur At Talah escarpment is located in south central Libya, the southern peripheries of Sirt Basin. The escarpment (height ≈ 130m and length ≈ 150 km.) can generally be considered as the exposed part of Abu Tumayam Trough. The outcrop is built up with marine to deltaic clay, silty clay and various sandstones, it is attributed to the Upper and uppermost Eocene time. Only a few field studies have previously been carried out to this area, those were mainly attracted to its vertebrate fossil-content. For the moment, sedimentology and depositional environment are poorly documented. Taking into consideration the importance of Dur At Talah escarpment outcrop, at the southern fringes of the large hydrocarbon bearing Sirt Basin, this paper aimed at defining the main facies, encountered in the exposed sequence. Sedimentological investigation suggested that the greatest part of the outcrop, which is the lower and the middle (approx. the lower 100 m.) parts, are strongly tidal dominated. The upper part therefore, appears to show smooth changing from tidal to ‘pure’ fluvial, probably includes mouth bar environments. In order to compare the Libyan tidal facies exposed in this outcrop, to modern ones, several field trips were conducted to the modern “macrotidal” environment of the Bay of Mont St Michel, France. The comparison would contribute to the understanding of the sedimentological sequence encountered in Dur At Talah area. Main results, especially the comparison between fossil and modern environments are presented in this paper.
Thermodynamic Analysis for Nitric Acid Plant
A thermodynamic energy analysis based on the first and second laws were performed for small size nitric acid plant with a capacity of (20000 tons/year) to produce (50 to 60) % nitric acid. The lost work available energy to produce work was calculated for each unit and the total lost work of theplant was determined and found to be about (3.5MW), the lost work of the reactor unit represents (59.326%) of the total lost work. This means that irreversibility which causes lost work is severe for the reactor. Any improvement of the operating condition which reduces irreversibility of the reaction would improve the efficient use of energy of the overall plant, that is, reduce lost work or available energy for work. This method of analysis can be used to pinpoint location of excess energy use in the chemical processes. However, it is the role of process engineers to recommend ways to reduce such waste of energy to the minimum possible and yet keep the process feasible.
Systematic Description Ostracods Fauna from the Lower Tar Member(Zimam Formation) Northern Ghadamis Basin
Ostracods are widely used for geological studies due to their small size, widely distributed, and have had rapidly evolving lineage, so that we have studied these creatures from Zimam Formation (Lower Tar Member) exposed on the southern edge of the Ghadamis Basin in order to systematic accounts of Upper Cretaceous ostracods. Twenty seven samples were collected and processed from outcrop section north of Al Qaryat Al Sharqhia which belongs to the Lower Tar Member. Lithologically consists of marl, Clay, limestone, and dolomitic limestone with gypsum in parts. Eighteen species recorded belong to fourteen genera, four species has wide geological distribution in North Africa and the Middle East, one new species proposed (Cytherelloidea dabai) and the remaining species left under open nomenclature, although they shows similarities to earlier described fauna which reported from North Africa and the Middle East. The ostracods species recording from the Lower Tar Member indicate deep to shallow marine environments.
Study of Paraffin Wax Effect on Base oil flow Behavior
Some of Libyan crude oils are known to have moderate to high content of paraffin wax. Problems related to paraffin wax are adding to the cost of barrel. In this work, the flow behavior of blends made from two types of base oil (N150, N500) have been experimentally studied, the blends were formulated in order to simulate Libyan waxy crude oils, and to exclude any effects of asphalten, resins and sediments which are normally present in crude oil. The main equipment used in this study is a rotational viscometer, measurements were performed by measuring the rheological properties (shear rate, shear stress, yield stress, and viscosity) of the blends at four different wax concentrations [2%, 5%, 8% and 10%wt] and measurements performed at six different temperatures in the range (15 - 60ºC). The flow behavior of the blends found to vary with temperature ranging from Newtonian to Non-Newtonian flow behavior, the apparent viscosity found to increase with decreasing temperature. Furthermore, the measured yield stress of blends found to increase with increasing wax content and decreasing temperature
Rheology and Pipeline Start up Pressure of Raguba Crude Oil
Waxy crude oil is a valuable soft that undergoes long journeys from the well to the terminals through thousand of miles of pipeline in various parts of the globe that include deserts, arctic areas and sub-sea beds. Under such conditions, pipeline cease pumping with serious consequences both in cost of interruption of production and damages to the pipeline. This paper describes research carried out on Libyan waxy crude oil namely (Raguba) to study (1) the rheology of this crude oil under various conditions and (2) the start-up pressure of this oil when temperatures decrease below the gel point. The rheological data to be presented are extensive in that they cover a range of conditions of temperature below and above gel and pour point and cooling histories (from very low to rapid cooling, 0.1 to 6.5°C/min representative of conditions under pipeline operations). Steady and unsteady states rheological tests were carried out under controlled shear stress and shear rate using an MCR-501 Anton Paar rheometer. Experiments were also carried out to measure the extent of visco-elasticity. As for the start-up pressure measurement, the paper describes a laboratory pipeline rig developed for the purpose of conditioning the oil (setting a measured cooling history) and measuring the corresponding start-up pressures after a range of stoppage time of 1, 2, 4 and 6 hours. The data obtained shows a good agreement between the yield stresses measured in the rheological tests and the start-up pressure tests but only when conditioning of the oil in the pipeline rig is duplicated in the rheological tests. The data also give practical guidelines on the minimum pressures required after certain time of pipeline stoppage. The data are useful in practice as they reduce excessive waste of power during pumping the oil.
Predication of Shear Velocity at Shaly Sand Reservoir Rock
The magnitude of shear velocity (Vs) in geomechanical rocks properties leads many of petrophysics and geophysics to use and investigate simple and accurate technique for it, especially when this parameter is not measured by sonic tools. If there are no core samples available for calibration, empirical relations could be used, that based on measurable physical properties. The results emphasize the importance of local calibration before one utilizes any of the empirical relationships presented. During this study several trials, were carried out aimed to predicate shear velocity in shaly sand reservoir of late Jurassic to Late Cretaceous at southeast of Sirt Basin, Libya, by using gamma ray, compressional travel time and density logs. Therefore, a new approach by modified derived Poisson’s Ratio Equation for shaly sand is introduced as an important part of shear velocity determination. This modified equation design upon deeper, highly compacted and cemented sandstone has a Poisson’s ratio values range between (0.18 – 0.20), which is fairly similar to the studied reservoir condition.
Water Shutoff Polymer/Gel Treatments for Oil or Gas Production Wells
IFP water shutoff technology is based on the use of Disproportionate Permeability Reducers (DPRs), i.e., polymers or weak gels that reduce selectively the relative permeability to water with respect to the relative permeability to oil or to gas. The products are usually injected into the whole open interval, without zonal isolation, which is a very attractive option compared to plugging gels proposed by service companies. IFP DPR products are water-soluble polymers, which are either swelled or weakly cross-linked in situ to increase permeability reduction to water, without impairing oil or gas permeability. The chemicals have been chosen to have minimal environmental impact. Each combination covers a specific domain of temperature and salinity. IFP water shutoff processes have been applied in a broad range of well and reservoir conditions, thus showing a high potential for future developments. Treatment design has to be adapted to each specific case. It requires both laboratory work to optimize gel formulation, and reservoir simulations with an in-house WSO model, to size up gel slug and gel strength. Several successful field cases are described, including gas wells, heavy-oil horizontal wells, and multi-layer water-flooded wells.
Copyright (c) 2005 PRC Petroleum Research Journal
The Use of Complex Wells for Reserves Optimization in the Mabruk Field
The Mabruk field, located in the Sirt Basin, is made up of four oil accumulations, namely North Mabruk, East Mabruk, Central Mabruk, and West Mabruk. The latter one, where fair reservoir characteristics were encountered, is the most extensively developed. The Mabruk carbonate reservoir, located at a depth of 3500 ft, is characterized by steep variations of facies together with a complex compartmentalization, resulting in massive reservoir heterogeneity. Several attempts were made by various companies since the late fifties to develop the field with vertical wells. But due to the small thickness (45 ft) and low reservoir permeability, the performance of vertical wells is generally poor. Since 1995, the approach used by Compagnie des Pétroles Total Libye (CPTL) succeeded in developing and increasing the reserves in the West Mabruk field by using sophisticated drilling techniques. The use of horizontal and multilateral wells allowed coping with the low productivity and alleviated the impact of heterogeneities. Reservoir simulation was also utilized to predict the areas that will be poorly swept, and plan infill drilling. A gradual increase of forecasted recovery from 19% in 1995 to 28% today resulted from this approach. The next stage of the Mabruk development will be to capitalize on the knowledge gained in West Mabruk, to adapt in the other parts of the Mabruk field (particularly the East and Central areas). Also, a review of the well performance and the improvement in geological understanding should lead to further improvements in future well design, including: well geometry, spacing, simulation and intervention strategy, and water injection scheme. This paper discusses the development philosophy followed so far, and the foreseen improvements currently under study to further improve the ultimate recovery factor in the field. Preliminary results from the ongoing investigations are also presented.
Re-establishing Reservoir Performance by Revaporization of Condensate in the Nubian Sandstone Reservoir
The Nubian Formation is a significant hydrocarbon reservoir in the NC 98 Concession of Libya. It consists of a low to medium permeability, fine-grained sandstone. Reservoir fluids in the Nubian are either very rich retrograde condensate gas or volatile oil. In either case, the reservoir pressure is at or slightly above the saturation pressure. Because the gas-containing reservoirs are very rich in condensate, small decreases in pressure often result in high volumes of condensate accumulation. Similarly, for the volatile oil case, small decreases in pressure result in large fractions of the volatile oil turning into the vapor phase. Both of these phenomena can result in adverse relative permeability effects which can reduce the permeability to the primary hydrocarbon being exploited. Laboratory experiments were conducted to characterize the phase behavior of the reservoir fluids. Conventional core analysis provided good coverage of the petrophysical description of the reservoir rock. Subsequent core flow experiments determined baseline flow to reservoir gas followed by the impairment to permeability at a series of pressure decrements. The pressures modeled in the laboratory were chosen to closely approximate anticipated field conditions. Laboratory results indicate a moderate to severe effect on permeability, caused primarily by the high critical saturation of condensate necessary for flow of condensate to occur. To mitigate the effect of condensate on permeability, laboratory experiments were performed to determine the viability of condensate removal through revaporization by gas injection.
Re-Development of a Mature FieldFor Production Acceleration, Intisar 103E Field
This paper presents a successful re-development and production acceleration project of Intisar E Field, Upper Girs A, B and C reservoirs of the Zueitina Oil Company. The project was implemented from 1999 to 2002 on the bases of a reservoir simulation study. The re-development plan comprised drilling 6 vertical injectors and 6 horizontal producers, and re-completion of existing 8 wells as commingled and/or dual producers. As a result of this project, the oil production potential of Upper Gir reservoirs has been increased almost by three folds from an average of 6,400 STB/D in 1999 to 20,000 STB/D in September 2002. The incremental reserves are predicted at 33.4 MMSTB until the year 2022.
New Parallelized Adaptive Implicit Methods for Large Compositional Reservoir Simulations
Simulation of large compositional reservoir models in an acceptable CPU time still remains a key issue for any reservoir simulation software. Parallel computing is thus required to speed up the simulations and robust numerical solutions need to be implemented to ensure accurate results, especially for simulations of complex compositional physics. In that context, classical fully implicit schemes are often not practical or, even unusable, due to memory and CPU restrictions. We propose new time discretization methods which mix the accuracy and stability of the fully implicit methods and CPU performances and low memory consumption of the explicit ones. Within these approaches, a fully implicit scheme is applied in parts of the reservoir with highest physical property variations, and an explicit method is used in the other ones. Explicit schemes are delimited by a stability CFL condition. Explicit cells with large variations on the unknown are switched dynamically to implicit ones to improve global simulation CPU performances. These status computations are based on either threshold or spectral criteria. Implicit grid blocks may also be discretized using fully implicit or quasi-implicit schemes depending on the fluid composition variations. These different schemes have been parallelized and integrated in a multi-purpose industrial reservoir simulator. The CFL criteria are discussed and tested on academic reference cases and then, comparisons of the available methods are presented for large compositional real case studies run on different parallel hardware platforms.
Naturally Fractured Reservoirs – Modeling and Simulation Methods
Natural or induced fractures play a crucial role in many petroleum reservoirs. Even though only a small percentage of today’s reservoir models explicitly describe the fractures or the fracture networks, one may claim that practically most petroleum reservoirs are fractured. Due to their complexity, but also due to their commercial significance, naturally fractured reservoirs have been the subject to extensive studies during the past decades. This paper will try to assess the current situation and methodology for modeling fractured reservoirs. Its main focus will be on recent developments in static and dynamic flow modeling of fractured reservoirs. Especially the latest Evolution in static modeling software capabilities significantly affected past historical workflows and initiated new developments in the reservoir simulation area. Starting from the historical evolution of dual continuum reservoir simulation models, a review is given on various simulation approaches for fractured hydrocarbon reservoirs. Several methods will be discussed, starting from conventional formulations to the traditional dual porosity model, to discrete fracture network models. All formulations have their own advantages, but have deficiencies in describing some other specifics of fractured reservoirs. Recently, the petroleum industry tries to integrate information from all possible sources to generate fracture network models and dual continuum simulation models. Most recently, the integration of seismic data into dynamic simulation models has received a great deal of attention. Also, latest developments in the gridding technology raised hopes to be able to cope with full permeability tensors in the near future. In many naturally fractured reservoirs, the fractures are found in limited zones, so-called “sweet spots” only. Consequently, not all parts of the reservoir models will typically require explicit fracture treatment with dual continuum models. One of the methods presented in this paper allows automatic generation of dual continuum grid blocks wherever the attributes of the geological model suggest to do so. This approach is called adaptive dual continuum model and it results in simulation models that contain grids that resemble the real geological situation very closely.
Nakhla Oil Field, Concession 97, LibyaDevelopment Strategy and Improved Oil Recovery
This paper presents the development strategy and the improved oil recovery potential of the Nakhla field. The Nakhla oil field is located in Concession 97 (G.S.P.L.A.J.) and is producing from the heterogeneous and compartmentalized Upper Sarir Sandstone since June 1995. Total production of the existing eight (8) vertical wells and one (1) horizontal well is approx. 22 MMSTB as of year end 2002. Seven vertical wells are hydraulic fractured and three wells are dry holes due to volcanics or technical problems. Within the next development phase (II) six (6) additional producers are planned. Based on the good experience all new wells will be drilled vertically and post hydraulic fractured. Updated static and dynamic simulation models have been used to optimize the development concept. Through natural depletion ultimate recovery estimates currently stand at 12.0% or 112 MMSTB. Further development (Phase III) is planned, but ongoing PreSDM and seismic interpretation has to be implemented to re-evaluate the geological and dynamic reservoir model. Ultimate recovery including Phase III estimates stand at 152 MMSTB or 16.3% of oil initially in place (OIIP). To increase the ultimate recovery even further the ‘Improved Oil Recovery (IOR)’ potential is currently under investigation. Available input data was reviewed and new SCAL and PVT including special IOR/EOR data was requested. Laboratory results will be available by end of year 2003 and will be implemented into a new compositional reservoir simulation. In the meantime a preliminary analytical screening was performed to identify viable IOR/EOR techniques and to estimate ‘Performance Indicators’ of the West and East field regions. Estimated ‘Performance Indicators’ vary between 13% - 19% for immiscible injection gas and 17% - 19% in case of miscible injection gas. In addition to improving oil recovery, the re-injection of produced gas would avoid gas flaring and confirm Wintershall’s policy to protect the environment. Water flooding is predicted to give good recoveries, too. However, low permeabilities may prevent or restrict injectivity into the reservoir. Further investigations are necessary and will be performed on a full-field compositional model.
Hydraulic Frac Stimulation of the Sarir Sandstone in Nakhla Oilfield
The Nakhla Oilfield is located in concession 97 within the Sirt Basin about 60 km south of concession 96. The field was discovered by drilling well G1-97 in 1970. 13 wells were drilled to date: nine of them are producing on natural flow, three found volcanics or volcanoclastic sediments replacing the entire or at least the oil-bearing, upper part of the reservoir, one technically failed in the Zelten Formation. All wells are producing from the Lower Cretaceous Sarir Sandstone. Low porosities of 10 to 14% and poor permeability ranging from 0.1 to 20 md only allow a moderate production. Therefore, hydraulic frac stimulation of seven vertical wells was performed between 1995 and 2002. State-of-the-art real-time analysis was performed in all hydraulic frac stimulations to evaluate and optimise the frac operation on-the-fly. Hydraulic frac simulation findings were compared to post-frac well test results obtained from pressure buildup analysis. Within their limits of accuracy, the frac parameters (e.g., frac half-length) obtained by both methods match reasonably well. This paper also summarises the lessons learned from the treatment executed and their impact on future operations and field development. The production behaviour of fractured and unfractured wells and the resulting additional production capacity is presented and discussed. To date, about 45% of the cumulative oil produced from Nakhla oilfield can be assigned to the hydraulic frac treatments. Especially during the last two years, a lot of effort was made to understand and describe the reservoir and its rock mechanical parameters better than before. The outcome was also implemented to improve the approach to plan and optimise future hydraulic frac stimulations.
Could WAG be the Right EOR Process for Libyan Carbonate Reservoirs?
n the Nafoora Augila Unit (NAU), one of AGOCO’s major oil fields, a significant volume of oil is expected to remain unrecovered within the prolific carbonate formations following conventional waterflooding. This paper highlights the critical role of experimental studies and technological research in supporting integrated simulation efforts aimed at assessing the technical and economic feasibility of Enhanced Oil Recovery (EOR) methods. Special Core Analysis (SCAL) data serve as a vital tool for calibrating reservoir models. Laboratory experiments conducted under actual reservoir conditions are essential to accurately represent fluid properties, wettability, and saturation endpoints. CO₂ gravity drainage experiments showed early CO₂ breakthrough and low displacement efficiency. In contrast, immiscible Water Alternating Gas (IWAG) displacement tests achieved oil recovery levels comparable to those observed in slim tube tests conducted at the Minimum Miscibility Pressure (MMP). This suggests that IWAG could be a viable EOR method for other immiscible gas injection processes—such as those using hydrocarbon gas, nitrogen, or fuel gases—at significantly lower pressures than MMP, particularly in carbonate reservoirs with similar depositional environments and diagenetic characteristics, including selective dissolution.
Field Applications of a Productivity Tool for Improved Oil Recovery (IOR)
In recent times, the oil industry has shown increasing awareness toward maintaining optimum well productivity through improved high-pressure, high-temperature (HP-HT) drilling and completion fluid design. However, the mechanisms of drilling fluid filtration and its impact on productivity performance under downhole conditions remain poorly understood. In open-hole completions, productivity losses are particularly critical because near-wellbore damage is not bypassed by perforations. Moreover, a satisfactory model for simulating near-wellbore damage in terms of well flow performance—based on laboratory core test analysis—is still lacking for field applications. This study presents results from extensive experimental data and analysis of static and dynamic filtration models. These results form the basis for semi-empirical mechanistic models, which have been integrated into a design and evaluation tool—the Productivity Tool (PRT). This tool predicts the effect of HP-HT drilling fluid filtration on formation productivity, specifically in terms of formation damage in vertical wells. in this paper, we present applications of the PRT using field data from North Africa oilfields with both water-based and oil-based muds (WBM and OBM), both selected as suitable for HP-HT wells. The PRT shows good agreement with the field measurements.
Depressurization as an Effective IOR Strategy
Reservoir depressurization is increasingly being recognized as the most cost-effective Improved Oil Recovery (IOR) technique in many clastic reservoirs. Early research into reservoir stress analysis has revealed a complex relationship between reservoir flow properties and the prevailing effective stress conditions. This paper presents findings from a series of studies conducted at The Robert Gordon University over recent years. These studies reaffirm earlier research, demonstrating that reservoir flow efficiency and recovery factor are significantly influenced by initial reservoir permeability, the Reservoir Quality Index (RQI), and the stress path. Preliminary results suggest that the impact of the stress path on flow efficiency and recovery factor is dependent on both RQI and the Flow Zone Indicator (FZI). FZI is a distinctive parameter that integrates geological characteristics such as texture and mineralogy to differentiate pore geometrical facies, referred to as hydraulic units. The stress path represents the magnitude of stress anisotropy within a reservoir. Stochastic analyses have been conducted using various field data, and the results can be utilized to guide decisions regarding optimal reservoir candidate selection and the operating conditions necessary to ensure successful improved oil recovery.
DELINEATION OF MINERAL POTENTIAL ZONE USING GIS IN THE SOUTHERN PART OF LIBYA
The powerful tools of Geographic Information System (GIS) and remote sensing (RS) have significantly contributed to the modern geological mapping and mineral exploration by enhancing, interpretation and integration of various geological datasets. Integration of remote sensing and airborne magnetic data with other geological data sets are the most promising and cost-effective method to add new structural and lithological aspects to the map of the geology in a diverse geological province as in the area of current research. This is due to the fact that all the geosciences information together with pre-processed remotely sensed data can be used as evidence to delineate possible areas for further study and more investigation (Chang-Jo & Fabbri 1993). The study area is a belt of Upper Devonian sedimentary formation including iron ore bearing layers, which extend over about 160km, in ENE-WSW direction, on the northern border of the Murzuq Basin. The study area is located in the western central part of Libya within the bounder’s 27º South and 28º North Latitude and 12º to 16º East-longitude covering an area of nearly 40,000km2. This study examines the integration of aeromagnetic data with remote sensing to discover any probable extensions of iron ore deposits and any associated minerals in the area of study. The study involves analysis of magnetic data to delineate geological structures, faults and to extract important information about the locations of buried magnetic bearing rocks. Spatial data integration and analysis for the study area and predicting mineral potential were carried out on the available digital remote sensing data (Landsat ETM+).
Copyright (c) 2022 PRC Petroleum Research Journal
OFF ROAD AND MARINE DIESEL FROM LIGHT GAS OIL,VACUM GAS OIL AND KEROSENE BLEND
Vacuum gas oil (VGO) produced by Benghazi Asphalt Factory and light gas oil (LGO) used in north Benghazi power plant were mixed in different volume ratio to produce a fuel blend. Kerosene was added in a small different volume ratio to reduce viscosity and improve cold flow LGO/VGO fuel blend property. LGO/VGO fuel blend pour point, flash point, volatility, copper corrosion properties, heat of combustion, water content, ignition quality and ash content are within the range of diesel fuel and light gas oil specifications. Viscosity and sulfur content of fuels A and C are within the range of diesel fuel classified A2 and marine diesel specifications whilst, carbon residue is slightly higher than that of diesel fuel classified A2 and No. 2-D specifications.
A FRAMEWORK FOR ENHANCING THE DECISION MAKING PROCESSES TO DEVELOP OIL AND GAS FIELDS WITHIN SOME LIBYAN OPERATING OIL AND GAS COMPANIES
Decision Making Process (DMP) is considered to be as a set of connected steps, adapted to accomplish desired objectives within any organization. This paper aims to develop a framework for enhancing the DMP within some Libyan oil and gas operating companies. Required data were gathered through an intensive literature-review, personal interviews, and an intensive questionnaire. Based on data analysis, the main findings indicated that the procedures being used for making decisions related to developing oil and gas fields need to be seriously improved, well-documented, and should be designed for enhancing the quality of the DMP. One of the challenges that confronted DMP is found to be the required time for gathering and analyzing the data to make the proper decisions. For developing the framework, PDCA cycle was used, containing four phases; each curtained steps to achieve the desired goals. The framework seeks to enhance the decisions’ quality in order to improve the performance throughout practicing the most effective tools and advanced techniques within this business area.
THE ACTION OF SILVER BENZOATE AND BROMINE ON AROMATIC COMPOUNDS AND ALKANES
Silver benzoate and bromine react in a heterogeneous phase with certain aromatic compounds and alkanes. Data on the ratios of bromination reaction on primary, secondary, and tertiary hydrogens suggest a mechanism involving an electrophilic radical attack as most probable in the presence of certain intermediates.
HYDROCARBON HABITAT IN THE SIRTE BASIN NORTHERN LIBYA
Oil-Prone organic facies II of the marine Upper Cretaceous (mainly Campanian) Sirte Shale is characterized by its micritic facies. Located in the eastern Sirte Basin, it is significant in oil generation due to sufficient depth of burial for thermal maturation. This information is based on geochemical data collected over many years by the Petroleum Research Centre. The combination of favorable organic facies and maturation level of the Sirte Shale defines areas of major oil generation in the Zella, Marada (Hafga Trough), and Ageadabia Trough. Giant oil fields tend to occur within short distance migration range from these oil-generative depressions. The evolution of the various segments of the Sirte Basin, in terms of their remaining potential hydrocarbon prospects, can be made by employing conventional methods of petroleum geology in conjunction with precise knowledge of where and when oil was generated in the various segments of the basin.
FAILURE ANALYSIS OF A WIRE - LINE DUE TO CORROSION FATIGUE. " Short Note"
INTRODUCTION: Steel wire-lines often operate under severe conditions such as alternating stresses, high bending moments, and hostile environments. The reliability of wire-lines is crucial for ensuring the efficiency of their multi-purpose operations.
Jamahiriya produces about 1.5% of the world’s methanol. The world capacity of methanol is expected to increase by 5% annually. Methanol is directly used as a blend to motor gasoline. A study was conducted to assess different technologies for methanol-based products and to optimize the production capacities of formaldehyde and acetic acid from methanol. The study also evaluated economic plans, energy costs, and the level of operations on the objective function. Enhancement ratio, pay-out period and rate of return on investment are calculated using the model to assess their sensitivity to the model’s parameters. Acetic acid plant produces a rate of return of 10% at relatively small capacity of 40,000 tons/year. Formaldehyde plant has a negative rate of return at a similar capacity. Formaldehyde plant is feasible with minimum capacity of 45,000 tons/year as partial local utilization is projected. Evaluation of formaldehyde plant as a source of generating foreign currency leads to encouraging results.
BIBLIOGRAPHY OF THE GEOLOGY OF SIRT BASIN AND CYRENAICA PLATFORM.
“BIBLIOGRAPHY OF THE GEOLOGY OF SIRT BASIN AND CYRENAICA PLATFORM." Compiled by M.T. Busrewil
A VISCOSITY BLENDING MODEL FOR LUBRICATING OILS " Short Note "
Introduction : Any suitable lubricating oil performance can be modified by controlling the amounts of different cuts and using additives so as to give lubricating oils a broad range of uses. Blending of different cuts of lubricating oil ranges of Brega crude had been investigated to obtain an optimum base oil before adding any additives. Preference for wax-free crude oils in the production of lubricating oils is discussed. Solvent extraction and dewaxing enable the use of a wider range of crude oils. The type and concentration of additives in lubricating oils vary based on applications, types of operations, and the ranges of cuts used in the blending program.
SUSCEPTIBILITY OF WELDING JOINTS TO STRESS CORROSION CRACKING IN AERATED 3.5% NaCl WATER SOLUTION
Susceptibility of welding joints of low-carbon steels to stress-corrosion cracking (SCC) is not clearly established. Such steels are generally not susceptible to that type of corrosion, but many failures have been observed in welding zones where subcritical crack growth was suspected to be a cause of catastrophic crack propagation. This work consists of the first set of research results performed on samples cut from welded 40 mm thick steel sheets exposed to a 3.5% NaCl water solution. The specimens with the tip of V-notch placed method in a fusion zone were tested by the cantilever beam method in an open circuit condition. The mechanism of SCC susceptibility ratio Kscc/Kc was 0.72. This value belongs to the highest class of susceptibility to SCC. The mechanism of crack propagation is believed to be a mixed mode of ‘hydrogen-induced embrittlement’ due to active path (or ‘martensitic’) structure and ‘pre-existing cracks are present.
Validation of Theoretical Coning Models Using Numerical Single-Well Simulation
Water coning is often a serious operational problem in oil reservoirs producing with strong bottom water drive. In Libya, many of the oil fields have water coning problems. The Production from such fields would normally consider limitation of the production rate to a certain minimum (critical rate) to prevent water coning from happening. However, since such a rate is normally very small (i.e., not economical), the company will be producing at a higher rate, and it becomes essential to estimate the time required for the water cone to reach the lower perforations (i.e., breakthrough time), and to predict the water performance afterwards to make the proper design for the surface facilities. Some of the published correlations for predicting the critical oil rate, breakthrough time, and water cut performance were applied to actual well data from three Libyan wells. Also, a single well 2D radial model was constructed on selected wells. The model results were compared to the actual field performance as well as to the correlations results. This study shows clearly that some of the empirical correlations can be considered more reliable than the others. It also shows that even though simulation of water coning is possible and gives more reliable results, the lack of data (i.e., good reservoir description, lack of vertical permeability data on a layer basis, lack of reliable special core analysis, and improper documentation of work-overs) will always limit the validity of the coning results obtained by the numerical models, especially at late times. Finally, this study is mainly aimed to set up the proper procedure of analyzing the water coning phenomena. Since the study considers the actual field data of only three wells, it should be expanded to a larger number of wells producing from different formations to confirm (or disconfirm) the results and conclusions of this study.