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Fagelnour, Mohamed (Khalda Petroleum Company) | Gamil, Islam (Khalda Petroleum Company) | El Toukhy, Magdy (Khalda Petroleum Company) | Gharieb, Ali (Khalda Petroleum Company) | Saad, Hesham (Apache Egypt)
Source rock potentiality and maturation of organic matter are important for petroleum system evaluation. Oil to source correlations helps in determining migration pathways. A set of geochemical analyses, including Rock-Eval pyrolysis and gas chromatography, and burial history modeling have been used to evaluate the potential source rocks and the generation of hydrocarbons in northern Shushan Basin, Western Desert of Egypt. The cutting and core samples cover the section from the Middle Jurassic Khatatba to the Upper Cretaceous Abu Roash formations. The main objective of this study is to determine source rock potential and maturity, the timing of hydrocarbon generation, and to characterize and correlate the bitumen extracted from Alam El-Bueib (AEB) and Khatatba rocks with the oil recovered from Bahariya reservoir. Results show that only a thin interval in AEB-3A and AEB-3C units are capable of generating moderate amounts of gas with some oil. Unlike other parts of the northern Western Desert, the older Khatatba rocks do not appear to contain significant amounts of good quality Kerogen. The Bahariya reservoir oil was derived from mixed organic matter source (algal-terrestrial) and is mature. It is believed that Bahariya oils were sourced from AEB rocks with a minor contribution, if any, from the Khatatba Formation. The normal faults dissecting the area act as migration pathways from deeply seated source rocks to more shallow reservoirs.
The Shushan Basin includes many old oil and gas fields in the north Western Desert of Egypt. Khalda oil Field lies approximately 460 Kms. West of Cairo and 70 Kms. south of the Mediterranean Coast (EGPC 1992, Schlumberger 1995). It lies at the northeastern part of the Shushan Basin in the Western Desert (Fig.1). It was discovered in November 1980 by drilling Khalda-1X well. In 1984, Khalda-2 well was drilled and proved the southern extension of Khalda Field. Currently, Khalda oil Field is under development with up to 100 producing and injector wells. The northeastern margin of Shushan Basin is controlled by NE-SW trending faults, offset by later NW-SE wrenching. These faults throw Mesozoic rocks against older strata. The structure on top Bahariya Formation is an oval anticline, dissected by NW-SE trending normal faults. Minor faults (< 50 ft. throw) offset the Bahariya Formation and isolate the pay zone into several fault blocks within the field (Fig.2). Bahariya Formation is the main oil-producing reservoir and composed of sandstone alternating with shale and siltstone streaks, with minor limestone and dolomite. It is divided into Upper and Lower Bahariya members.
Abbas, Islam (Khalda Petroleum Company) | Guinn, Stewart (Khalda Petroleum Company) | Afify, Waleed (Khalda Petroleum Company) | Ramadan, Yasser (Khalda Petroleum Company) | Jennette, Dave (Khalda Petroleum Company) | Gharieb, Ali (Khalda Petroleum Company)
While exploring for Jurassic hydrocarbons in Shushan Basin, North Western Desert, Egypt, Partial or complete reservoir substitutions, alteration by volcanic, volcaniclastic deposits have led to a number of unsuccessful wells. It is therefore essential to understand the distribution and geometry of volcanics in the vicinity of the Jurassic reservoirs. Many wells have been drilled and the presence of volcanic rocks were not recognized for more than a decade. The Qasr NE -2X well was the first alert that volcanic rocks occur in the Jurassic section. This paper shows detailed integration between spectral GR, triple combo, spectroscopy and image logs were necessary to define and differentiate between volcanic rocks of similar composition or alteration from similar host rocks. The lithostratigraphic cross sections and thickness variations of Jurassic volcanics are discussed in order to distinguish the shape and the extent of the volcanics, but the key is to be able to recognize the volcanics away from well control. The results showed that the emplacement of Jurassic volcanic rocks were from extrusive volcanic events. Thin section and log response of olivine basalt and tuffaceous caps strongly suggest sub-aerial effusive eruption. The identification of volcanic rocks using 3D seismic data is critical from a prospecting point of view. If we are unable to see the volcanic seismic signature we cannot predict their presence. If the volcanic rocks as described above vary from tuffs, altered basalts to un-altered basalts then the resultant reflection coefficients will also vary and in some cases will be similar to the sedimentary country rocks. Other factors with regard to seismic imaging of variable volcanic rocks are thickness, spatial distribution, and seismic data quality. We are studying the response of volcanic rock types using VSP data and well based synthetics and some results are described in this paper. A number of seismic attributes were evaluated including AVO modeling.
Emam, S. S. (Blade Energy Partners) | Brand, P. R. (Blade Energy Partners) | Gabaldon, O. R. (Blade Energy Partners) | Vityk, M. (Shell Egypt) | Leithy, A. El (Shell Egypt) | Shanab, M. Abou (Shell Egypt) | Hamdy, B. (Shell Egypt) | Abdel-Moniem, M. (Shell Egypt) | El-Desouky, W. (Badr Petroleum Company) | El-Azm, H. Abo (Badr Petroleum Company)
The BTE – 2 was planned as a land based deep vertical exploration well in Egypt (the deepest ever drilled by Bapetco), designed to evaluate the Abu Roash, Bahariya and Kharita formations, testing the Kharita gas reservoirs and leading into the development of the entire BTE prospect. The complexities included HT classification, formation pressures uncertainties, deep total depth, and introducing a new technology, Managed Pressure Drilling (MPD), to the rig.
MPD played a pivotal role in the major discovery of the exploratory "BTE – 2" well, which led to initial estimated in place volumes of 0.8 TCF for the BTE prospect. MPD allowed the operator to reach the reservoir section by successfully navigating the 0.45 ppg operating window in the upper section. MPD also created a wide range of benefits throughout drilling the 1080 meters section, including managing the BHP through the narrow drilling window, real time prognosis of the pore pressure and fracture gradients incorporating the use of Pressure While Drilling technology, efficiently managing drilling through severe conditions, optimizing logging operations and MPD running and cementing of the 7 inches liner.
A high Intensity kick was detected by the MPD system in Abu Roash "G" formation. Implementing the MPD assisted shut in method helped minimizing influx size. The kick was initially circulated conventionally and the MPD system was engaged during the second circulation while slightly increasing the Mud Weight.
Using the MPD system helped to control the annular pressure profile during multiple rig pump problems and motor stalling events. Due to the small operating window, running the 7 inches liner was a major challenge, even while using the MPD system. Non homogeneous drilling fluid, high loss rates and high PP added complexity to the process. Establishing a closed loop system created a safer and better monitoring and controlling system for the 7 inches liner running operations.
Managed Pressure Cementing was the only valid and reliable method to cement the 7 inches liner in place. The MPD system was used to manage the slim drilling window, and the Coriolis flow meter helped to identify the required pressure values to minimize associated losses.
Employing the MPD Constant Bottom Hole Pressure (CBHP) technique resulted in numerous learnings, especially when the MPD technique is a first use for the drilling rig crews. This paper highlights and emphasizes the distinguished learnings (not specific to a particular project) that could help in planning and implementation of future MPD wells.
Abouzaid, Ahmed (Baker Hughes) | Thern, Holger (Baker Hughes) | Said, Mohamed (Baker Hughes) | ElSaqqa, Mohammad (Khalda Petroleum Company) | Elbastawesy, Mohamed (Khalda Petroleum Company) | Ghozlan, Sherin (Khalda Petroleum Company)
The evaluation of logging data in shaly sand reservoirs can be a challenging task, particularly in the presence of accessory minerals such as glauconite. Accessory minerals affect the measurements of conventional logging tools, thus, introducing large uncertainties for estimated petrophysical properties and reservoir characterization. The application of traditional Gamma Ray and Density-Neutron crossover methods can become unreliable even for the simple objective of differentiating reservoir from non-reservoir zones.
This was the situation for many years in the glauconite-rich Upper Bahariya formation, Western Desert, Egypt. Formation evaluation was challenging and the results often questionable. Adding Nuclear Magnetic Resonance (NMR) Logging While Drilling (LWD) data in three wells changed the situation radically. The NMR data unambiguously indicate pay zones and simplify the interpretation for accurate porosity and fluid saturation dramatically. Key to success is NMR total porosity being unaffected by the presence of accessory minerals. NMR moveable fluid directly points to the pay zones in the reservoir, while clay-bound and capillary-bound water volumes reflect variations in rock quality and lithology.
Although the NMR total porosity is lithology independent, the presence of glauconite affects the NMR T2 distribution by shifting the water T2 response to shorter T2 times. This requires an adjustment of the T2 cutoff position for separating bound water from movable hydrocarbons. A varying T2 cutoff was computed by comparing NMR bound water to resistivity-based water saturation. The calibrated T2 cutoff exhibits an increase with depth indicating a decreasing amount of glauconite with depth throughout the Upper Bahariya formation. Based on these volumetrics, an improved NMR permeability log was calculated, now accurately delineating variations in rock quality throughout the different pay zones. In addition, viscosity was estimated from the oil NMR signal. The estimated values match the expected values very well and illustrate the potential of NMR to indicate viscosity variations.
Many of these results are available today already in real-time by transmitting NMR T2 distributions to surface while drilling. Besides the application for formation evaluation, the data can be used to initiate optimized side-tracking and completion decisions directly after finishing the drilling operations.
The northern Western Desert Basins of Egypt experienced a complex evolutionary history and several transformation of tectonic stress field properties. An integrated analysis of geological and geophysical data reveals that structural inversion, reactivation and extensional detachment develop in the area, and have a significant effect on formation and preservation of hydrocarbon accumulations. Such an analysis is paramount for prospect evaluation, risk mitigation, and therefore improving the exploration success rate.
The rifting in Jurassic and early Cretaceous formed several faulted-depression basins with boundary normal faults in the area. A few boundary normal faults were reactivated in late Cretaceous to Eocene period as reverse faults with dextral compressive features, giving birth to a series of inverted anticlines over them. Compressive wrenching movement on the boundary faults greatly weakened their lateral sealing capacity and accordingly enhanced the vertical conduit capacity of hydrocarbon migration from the Jurassic source kitchen to Cretaceous inverted anticlines along the boundary faults. This is why Cretaceous inverted anticlines show a high concentration of hydrocarbon accumulations whereas there are few oil discoveries in the lower Alam El Bueib (AEB) formation and Jurassic along the boundary faults.
Reactivation of basin boundary normal faults in late Tertiary to present abounds in the area. Most of them are surface penetrating, which are vital to the existing hydrocarbon accumulations because the reactivation could not only make poor the preservation of the existing hydrocarbon accumulations and cause the redistribution of hydrocarbons, but also it would destroy the existing hydrocarbon accumulations. Some unsuccessful wells can be attributed to the reactivation of basin boundary normal faults in late Tertiary to present. Some prospects associated with the reactivation of basin boundary normal faults have the same or similar hydrocarbon preservation risks as the unsuccessful wells.
By integrating seismic interpretation and lithologic assemblage and thickness variation of the AEB formation, an extensional detachment fault was recognized in Alamein Basin. The detachment, located in the mudstone-dominated AEB 5-6 intervals, makes hydrocarbon migration difficult from Jurassic source kitchen to Cretaceous traps because the vertical migration pathways have been cut off by it, and are unfavorable for the formation of hydrocarbon accumulation above it.