bluuebunny/crossref_metadata_2025_split huggingface dataset:
Uncertainty Evaluation in Emerging Gas Projects in North Africa Using Geological Modeling, Reservoir Simulation and Experimental Design
Authors: Vicente M.. , Moreno F. J. , Limeres A.. , Ozamiz E. Izaguirre , Rieu R.. 
Published: February 2010

Abstract
In this study the main uncertainties affecting the reserves estimation in the low permeability Lower Devonian gas reservoirs of an exploration block in Algeria are evaluated. This large gas project faces significant uncertainties as a result of the ambiguities in reservoir quality, architecture and well performance. Therefore, a comprehensive risk analysis is essential to manage the production forecast and the surface facilities sizing evaluation.
Although there have been important advances in terms of reservoir modeling and simulation, the reserves risk analysis remains as a challenging task in the early exploration phase of large projects. Traditional studies commonly use only one geological model for the simulation (P50 or mean case), and the uncertainties are evaluated using a one-parameter-at-a-time approach assuming no dependency among them. Finally, this unique case is adopted to take decisions based on the economic output results analysis and the project commitments.
An alternative to the traditional evaluation is the use of Experimental Design (ED). An analytical equation ("response surface model") is created and this surrogate model is used to study the interaction of all variables and their impact on the simulations. The experimental design coupled with multivariable regression and Monte Carlo simulation could be used for final parameters evaluation. Relatively few real case examples of this technique have been documented, and commonly these applications do not integrate multiple deterministic geological models.
In this paper we present an example of how static and dynamic uncertainties were integrated using a scenario-based approach and ED, building the models and concentrating the study on the variables that control the recovery: reservoir quality, distribution and connectivity, porosity, permeability and fluid contacts. This work helped to quantify the uncertainty for reserves, number of wells and gas rate deliverability estimation, adding significant value to the current field development plan assessment.
Qualitative and Quantitative Interpretation: The State of the Art in Temperature Logging
Authors: Valiullin R. A. , Ramazanov A. Sh. , Pimenov V. P. , Sharafutdinov R. F. , Sadretdinov A. A. 
Published: February 2010

Abstract
In the paper it is described the achievements in the modern well thermometry and analyzed the problem of quantitative interpretation.
It is known the first logging in oil wells was temperature one. In 1906 the professor D. Golubyatnikov on Apsheron (Azerbaijan) at first time measured the temperature distribution along the wellbore using the maximal thermometer. Today the high sensitive electronic thermometers with resolution of 0.01K are used: it is registered and analyzed the temperature changes of hundreds and tens parts of degree, caused by Joule -Thomson effect and adiabatic effect.
At present time the most volume of production log is accounted to thermometry. In the paper it is given the examples of field cases from Russia by means of well thermometry during the development using the gas (air) compressor. The results of practical testing of new methods of well thermometry as "active thermometry", which is based on local inductive heating of casing on the different depths and observing the behavior of the transient temperature, are discussed.
It's known that despite many attempts to develop quantitative interpretation methods, the interpretation of temperature measurements has remained mostly qualitative. The paper describes the mathematical models, used at interpretation of temperature logs. The most recent results are connected with quantitative interpretation of quasi-steady temperature distribution along the well and pressure and temperature transients with the purpose of determination of flow rates and individual parameters (for example, radius and permeability of damaged zone) of formation in multilayer wells. The application of the developed models to interpretation of temperature measurements in the different wells demonstrated on real field data sets.
3D Exploration for Remaining Oil Using Historical Production Data
Authors: Ling Yun , Huang Xuri , Guo Xiangyu , Sun Desheng , Gao Jun , Lin Jixiang 
Published: February 2010

Abstract
3D and 4D (or time-lapse) seismics are techniques commonly used for exploration and reservoir exploitation. Increasingly, time-lapse seismic is becoming a more popular tool for reservoir development and management. However, its application is constrained by reservoir conditions, production mechanisms and seismic data repeatability. The technique of 3D exploration for remaining oil with historical production data (called a 3.5D seismic approach to differentiate it from time-lapse seismic) uses high quality 3D seismic data, acquired after a certain period of reservoir production, and integrates them with historical production data to provide information for reservoir dynamics, such as the identification of additional resources and the delineation of remaining oil. In integrating the 3D seismic with historical production data, the 3D seismic data are time-stamped and then related to the reservoir dynamics. This enables 3D seismic data to represent reservoir dynamics in time. In this paper we present a case study in an onshore mature oil field in western China, where no baseline 3D seismic survey is available, with production data spanning a period of 16 years from 1990 to 2006, and with a 3D seismic survey acquired in 2006. The results show that the 3.5D seismic approach can identify reservoir potential and remaining oil.
Enhanced Formation Evaluation and High-Resolution Facies Determination Using Spectroscopy Logs in the Nile Delta, Egypt
Authors: Van Steene Marie , Farghaly Adel , El Fotoh Ahmed Abu , Herron Susan 
Published: February 2010

Abstract
Computing clay volume using elemental neutron capture spectroscopy logs in combination with a multimineral solver for the complex, shaly sand reservoirs of the Nile Delta reservoir improved accuracy over using the mineral fractions output from the spectroscopy model alone. It was also found that the aluminium log from direct aluminium yield measurement leads to a better clay volume estimation, as opposed to using the aluminium log from the aluminium emulator algorithm.
Combining the spectroscopy data with borehole image data generated a high-resolution lithofacies column that provides an accurate stratigraphic interpretation. Applying cutoffs to generate a high-resolution sand count enabled us to sort the reservoir units from the poorest to the best quality sands and improved our understanding of the distribution of the best reservoir quality in the well. This approach provides a unique solution to characterize thinly bedded reservoirs in wells drilled with oil-based mud.
Challenges Facing Marine CNG Transportation
Authors: Nassar Yehya Mohamed 
Published: February 2010

Abstract
Natural Gas is recently becoming the more popular energy source worldwide and its use is expected to increase dramatically over the next two decades. Natural Gas has been gaining wider significant as a result of sustained high oil prices, a need for energy diversification and security, the growing global awareness of environmental issues, and due to the development of new gas-related technologies.
Traditionally natural gas has been delivered to markets using two main commercially-proven methods; Pipelines and liquefied Natural Gas (LNG). Each of these alternatives is highly capital-intensive and requires considerable working terms regarding the quantities and distances to market. In other words these two methods are only economic over a specified range of quantities and distances and not the whole range, which opens the door to a number of alternative technologies that have the potential to make the development for smaller quantities to be transported to specific distances.
The most advanced among these alternative technologies include Onshore Gas-to-Liquid (GTL), Floating LNG and GTL, Natural gas hydrates (NGH), Adsorbed Natural Gas (ANG) and Compressed Natural Gas (CNG). None of these however, has yet been developed and proven on a commercial scale, although they have proven themselves viable on technical parameters.
This paper will be concerned mainly with Marine CNG alternatives, which are currently in their final stages of commercialization, indicating the various available Marine CNG technologies used worldwide and focusing on the operating differences between LNG and CNG transportation and finally technically and economically evaluating both the obstacles and advantages facing the commercialization of Marine CNG transportation.
A Study of Coupling Surface Network to Reservoir Simulation Model in a Large Middle East Field
Authors: Al-Mutairi Saad , Hayder Ehtesham , Munoz Alberto , Al-Shammari Ahmed , Al-Jama Nayif 
Published: February 2010

Abstract
This study investigated the feasibility of coupling a subsurface numerical reservoir simulator (POWERS) with a surface network modeling simulator, to assist in making better field management decisions according to business need. Coupled simulation models have two advantages over uncoupled models. First, interdependence of the reservoir and surface facilities are properly modeled in coupled simulation models to accommodate rapid variations in production strategies. Coupled simulation models are likely to give more accurate production forecasts compared with modeling the reservoir or the surface separately. Second, given that most surface network modeling tools have a built-in optimizer, it is possible to allocate rates among wells based on a user's objective optimizing function, — e.g., reducing or maintaining a water-cut level for a given production target — taking into consideration any system production constraints applied on a well, a group of wells or trunkline levels. To improve the quality of simulation results, a new algorithm is implemented in POWERS to calculate the inflow performance relationship (IPR), based on drainage pressure, i.e., a reservoir pressure calculated as the average of several neighboring cells in the simulation model as opposed to the single cell pressure. The current study shows that it is feasible to run coupled POWERS-surface network models and gain the benefit from the optimization algorithm of the surface network modeling tool.
Effective Use of Resistivity Behind Casing to Improve Oil Recovery From a Brown Oil Field: A Case Study from the Western Desert, Egypt
Authors: Badr Abdallah B. , Mahgoub I.. , Dutta D. J. , Van. Steen M.. 
Published: February 2010

Abstract
Enhancement of oil recovery and reduction in water-cut in a matured field requires precise time lapse saturation monitoring. Behind casing resistivity, an important member of the comprehensive analysis behind casing services suite, provides required answer by acquiring deep resistivity information through casing and subsequent formation evaluation. A time lapse saturation figure could be generated immediately after the acquisition which is extremely instrumental to take immediate decision. The technology is well known in the industry and already proved beneficial in many occasions. In favorable conditions, this is the most effective methods available to date for saturation monitoring as being the deepest through casing measurement in terms of radial investigation.
The case study presented in the paper describes a successful water shutoff operation and enhance oil recovery from the Bahariya formation in the western desert, Egypt. The well was drilled in early 2006 followed by logging and testing and was put on production immediately after completion. Over about one and half year, the oil rate decreased by 70% with 86% water cut.This significant fall in oil output with sharp early water break through, a common phenomenon in this mature field required a proper shutoff operation. The present example discusses in detail the reason in choosing resistivity behind casing acquisition and time lapse formation evaluation to monitor present saturation profile. Comparison between original and present water saturation level immediately detects the depletion zones and the degree of depletion across perforated intervals indicates the interval contributes most of the produced water. In the present example the cased-hole resistivity acquisition shows departure (lowering) of resistivity values against some perforated intervals. The zones were isolated after identification of the intervals that shows considerable lower in values. This is considered as an indication of rise in oil-water-contact or lengthening of transition zone. In the present case, the remedial measures for water shut-off operation based on time lapse evaluation have enhanced oil recovery from 540 Barrel to 2250
Barrel oil per day with significant reduction in water cut from 86% to 1%.
The results were encouraging enough for the operator to reinvestigate the production performance and identify wells where this technique could be meaningfully utilized. The current analysis and workflow offers a fairly good understanding about the reservoir's production scenario, monitoring and future actions for enhanced recovery.
Application of a New Computer Aided History Matching Approach - A Successful Case Study
Authors: Gherryo Yousef S. , Shatwan Mohamed B. , Abrahem Fathe A. , Heinemann Zoltán E. , Mittermeir Georg M. 
Published: February 2010

AbstractThe reservoir, located in the Sirte Basin, Libya was discovered in the early 1960s. Since then, more than 65 wells have been drilled. By the end of the year 2008, more than 160 MMstb undersatured oil have been produced from the Upper Cretaceous. Water cut has risen to 65% and average reservoir pressure is still 1000 psi above bubble point. The individual well production history is highly influenced by water coning.The field is geologically complex; heterogeneous, contains numerous large and smaller normal faults sometimes associated with fractures, leading to local permeability enhancements. Average gross thickness is about 300 ft. Recovery is mainly (80%) by the strong edge water influx and by expansion (20%).The objective of the History Match (HM) was to accurately determine the distribution of the reminder movable oil, in order to enable reliable performance predictions of existing and future wells. To meet this goal, the total amount of produced fluids on a well-by-well basis as well as the average local pressure must be matched within close limits.Conventional HM techniques failed due to the complex geology and production history. Especially the highly variable water cut could not be matched satisfyingly. For this reason, a new HM method and workflow, called Target Pressure and Phase Method (TPPM), was applied. TPPM ensures, that the calculated average reservoir pressure and the calculated amount of produced liquids match the corresponding measured values at every point in time. This is achieved by regulation of water influx from artificial boundaries and automatic distribution of the inflow along the well trajectories. Thus, the engineer can immediately concentrate on matching the well-by-well performance leading to a considerable reduction in project duration. Additionally, TPPM gave excellent results in HM. Thus reliable future field operation scenarios can be designed and calculated. The presented workflow and method is generally applicable, especially for reservoirs under strong water influx.
Sweet Success in Sour Coring
Authors: Briner Andreas , Azzouni Abdul-Hameed , Chitnis Rajendra , Vyas Vishal 
Published: February 2010

Abstract
The South Rub Al-Khali Company Limited (SRAK) is a Joint Venture between Shell and Saudi Aramco and is engaged in exploring in the Rub Al-Khali Basin of the Kingdom of Saudi Arabia. The licence area contains significant quantities of ultrasour gas in the Jurassic Arab Formation reservoir. Acquiring accurate subsurface data forms a key objective for SRAK in its ongoing exploration drilling campaign in this remote and challenging desert environment.
Health, Safety and Environment (HSE) is at the forefront of SRAK's operations. This paper presents how extensive pre-job planning and proper execution of new procedures led to the safe and successful coring of the hydrogen sulphide (H2S) rich Arab Formation in the eastern Rub Al-Khali of the Kingdom of Saudi Arabia.
In SRAK's most recently completed well, five continuous cores, with a total length exceeding 350 ft were successfully cut, with a high recovery factor of 99%, covering the Mesozoic Arab C and D members of the Arab Formation. These gas-bearing reservoirs were known to be very rich in H2S and carbon dioxide (CO2) posing environmental and technical challenges for data gathering. Through strict adherence to extensive procedures and training, the operations were successful and were conducted safely and efficiently.
The operations were planned well in advance with a dedicated workshop incorporating the well engineering group, subsurface teams and the coring and core analysis companies. Detailed step-by-step discussions of the coring workflow identified gaps in existing core acquisition procedures. The coring contractor, based on the expected high levels of H2S, updated existing HSE coring procedures. Specific HSE procedures that covered the interface between the different parties were set-up and communicated. Mandatory H2S-specific training was extended to cover all staff, from logistics, operations team to the core analysis personnel.
In addition to the HSE aspects, the mud system and core barrel vibrations were closely monitored to guarantee good core recovery with a maximum of H2S scavenged. Special attention was also given to the cores after recovery to ensure no poisonous gas is released in an uncontrolled manner.
The data obtained from the Arab Formation cores has been a vital component in establishing SRAK's understanding of the geology, hydrocarbon-fill history and in-place volumes of the company portfolio.
The intention of this paper is to share the proven guidelines for coring, core handling and core processing, of rocks from H2S-bearing formations, for the benefit of other operators of sour gas fields.
Fast-Track Maturation and Development of the Al Fadl & Al Qadr Fields, Two New Discoveries, NEAG East, Western Desert, Egypt
Authors: Bakr Ahmed , Le Varlet Xavier , Postuma Willem 
Published: February 2010

Abstract
Al Fadl & Al Qadr fields are located in the eastern part of the Abu-El-Gharadig Basin (Western Desert, Egypt). The exploratory wells Al Fadl -1 & Al Qadr -1 were drilled late 2007, encountered under saturated oil in the Bahariya Formation (Cretaceous). The development lease was granted in January 2008 after the successful testing of the wells. Production started in April 2008. These discoveries offered an attractive opportunity to increase Bapetco's oil production. Due to its location away from the existing Bapetco facilities, Early Production Facilities were installed to enable production to start just after the development lease was granted. The development required an integrated and x-asset planning approach to accelerate its development and maximize hydrocarbon production without compromising other development. The main strategy was to fast-track maturation and appraisal/development opportunities in the area. The main aim was to expand Bapetco's operations and achieve early production, and prepare for the secondary recovery (water flood scheme). The Petroleum Engineering studies consisted in the construction of comprehensive 3D models of the marginal marine reservoir sequences capturing key uncertainties. The static models were exported to dynamic simulators. Geological, petrophysical and reservoir engineering data were integrated to create realizations reflecting extreme scenarios for reservoir parameters such as reservoir architecture, structure and fluid contacts in an attempt to define the in place hydrocarbon volume range, the static connectivity and to test the robustness of the development concepts. Dynamic models were used to provide forecasts for proposed realizations. Very successful multidisciplinary integrated study work resulted in fast track maturation of FDP and delivery of 27 well proposals within 6 months. The development scenario selected consists of an inverted 5 spot pattern (spacing between well producers of 600m, fracced wells, ESP completion). Currently the fields are producing through the EPF system while development drilling is delivering 2 producers a month. Water injection is planned to start in the Q1 of 2010.
Lower Safa Sedimentological Study, New Insights in the Reservoir Quality Distribution of the Obaiyed Field, Western Desert, Egypt
Authors: Saad Ahmed , de Groot Michiel 
Published: February 2010

Abstract
The Obaiyed gas/condensate field is located the Western Desert 50Km South of Marsa Matrouh. The Jurassic Lower Safa member (the reservoir bearing unit) consists of massive sandstones, which after deposition were subject to extensive deformation. A wide range of reservoir qualities is found in the field, with permeabilities ranging from tight (sub 0.1 mD) to high (up to 600 mD). Even after drilling 11exploration/appraisal and 30 development wells in the Obaiyed area, there are still significant subsurface uncertainties in the reservoir quality and extension, as shown by the 20% failure rate of the development wells. In order to improve our understanding of the Lower Safa reservoir, EREX Egypt was asked to make core descriptions for 15 wells in the Obaiyed field. They described 824m out of 1300 m total core length, to determine the depositional model of the Lower Safa. The conclusion of the study was that the main reservoir can be described as an estuarine deposit, with strong tidal influences in the earlier sequences, that evolved vertically into a wave-dominated deposit. The sedimentological study resulted in a simplified facies scheme that was used in Petrel to generate a 3D model for history matching. Unfortunately, it proved impossible to make a core-log correlation that could guarantee the successful production of new development wells. It was decided to take the reservoir quality uncertainty as a given and develop a completion strategy that would enable BAPETCO to produce the wells in any case. Therefore BAPETCO is planning a staged massive frac strategy in the coming years in parallel to the infill drilling campaign to maintain our production plateau and increase the ultimate recovery from the field.