This paper was prepared for presentation at the Unconventional Resources Technology Conference held in Houston, Texas, USA, 23-25 July 2018. The URTeC Technical Program Committee accepted this presentation on the basis of information contained in an abstract submitted by the author(s). The contents of this paper have not been reviewed by URTeC and URTeC does not warrant the accuracy, reliability, or timeliness of any information herein. All information is the responsibility of, and, is subject to corrections by the author(s). Any person or entity that relies on any information obtained from this paper does so at their own risk. The information herein does not necessarily reflect any position of URTeC. Any reproduction, distribution, or storage of any part of this paper by anyone other than the author without the written consent of URTeC is prohibited. Abstract Most of the Egypt's Western Desert plays are characterized as tight reservoirs. In early development stages, only the high permeability layers called "conventional reservoirs" were produced. The unconventional, challenging layers were not considered economical because of the high stimulation costs.
Prediction of the formation pore pressure is considered as a significant simulation process during the drilling and production phases of the carbonate reservoir. The deficiency in this prediction allows for the occurrence of many troubles like blowouts, kicks, hole washouts, wellbore breakout, and stuck pipe. The most common conventional methods for the pore pressure prediction are Eaton’s and Bower’s methods which depend mainly on the normal compaction trend and commonly applied on Shales. The objective of this work is the prediction of the formation pore pressure by the application of the modified Atashbari prediction model upon the wireline logging data. This method depend on the porosity and the compressibility attribute of the rocks for the estimation of the pore pressure without any need for the normal compaction trends. The method was applied on the carbonate reservoir of the Middle Eocene Apollonia Formation, Abu El-Gharadig basin, Egypt. It is a gas bearing reservoir which characterized by its high porosity and low permeability. The results were compared with the other commonly used methods and show an improvement in the pore pressure estimation. It can be used as an individual method or in complement with other available methods.
Formation pore pressure is defined as the pressure of the fluid filled the pores of the formation. It can be either equal to the hydrostatic pressure, which is known by normal pore pressure, or differ from the hydrostatic pressure (higher or lower), which is known by, abnormal pore pressure. Swarbrick and Osborne (1998) described several mechanisms that originates abnormal pressures such as aquathermal expansion, compaction disequilibrium (under-compaction), gas cracking and hydrocarbon extraction, hydrocarbon buoyancy, lateral stresses due to tectonic events and mineral transformations. The deficiency in the formation pore pressure prediction before and during drilling, increase the probability of drilling risks and incidents. Abnormally high pressures causes weakness in faults (Bird, 1995; Tobin and Saffer, 2009) and mud volcanoes (Davies et al., 2007 and Tingay et al., 2009). Pore pressure predictions in unconventional carbonate reservoirs, depending on well logs has always been a difficult task. Carbonates do not compact uniformly with depth as do Shales. In addition to that, the pore system in carbonates is a complex combination of several pore types, which increases the risk of erroneous pore pressure prediction (Wang et al., 2013).
With the increase of Egypt's domestic demand for energy, economical production from unconventional reservoirs is a great challenge to maintain production's annual decline. This has spurred interest in the development of unconventional resources, such as tight reservoirs and shale gas, particularly because of the enormous success in North America that brought unconventional resources to the forefront of the discussion on the future of energy. The country has launched studies to evaluate, explore and appraise several prospects for unconventional gas in Shoushan-Matrouh and Abu Gharadig basins. Exploratory pilot data wells were drilled and completed in the appraisal program for collecting the required data to evaluate the reservoirs qualities, demonstrate the availability of reserves, and identify optimal technology to maximize productivity and set the foundation for future development of these unconventional plays. Logs, core testing, and analysis service data were performed on or collected from these wells. Laboratory testing was conducted to understand the complex mineralogy and variable rock fabric. Geomechanical rock properties derived from advanced petrophysical analysis of newly acquired high-definition triple-combo full-wave sonic logs and core samples were combined to develop sophisticated models. These understandings helped reduce uncertainty and the lessons learned from this work and presented in this paper helped define completion and stimulation technologies for horizontal wells.
This objective of this paper is to review of the results and share lessons learned related to the recent appraising activities of unconventional plays in Egypt's western desert, evaluate these unconventional resources to unlock their potential. In addition, this paper present the challenges of development, highlight the best strategies required for field development to capitalize on the promising potential of these reservoirs through an integrated advanced workflow. The results from this study will shed light on the results of recent unconventional gas exploration and appraisal activities, which indicate that the western desert of Egypt holds substantial resources of unconventional gas. This unconventional gas can help to change the slope of production rates in the country positively and set the foundation for future development of these plays.
Objectives/Scope: Kuwait energy company has started to explore and develop oil and gas reserves since 2010 in East Abu-Sennan concession under production sharing agreement with the Egyptian General Petroleum Corporation. This concession is located in the Western Desert of Egypt, Production was commenced in July 2012 with 4 wells, oil production in this field was restricted due to gas flaring limitations in the agreement to 1 MMSCF/Day. Therefore, Kuwait energy initiated a challenging objective for the best gas utilization method in 2014. The project to be executed must pass the barriers of economic model with pessimistic reserve inputs and relatively short execution duration. Methods, Procedures, Process: Three scenarios were considered for Gas compression station: Brand new equipment, Rental Facility and Idle Used equipment. Risk assessment and economical modeling were performed and showed that Idle Used equipment existing in the country is the most economically feasible option.
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.
Abu Roash-D is characterized as a carbonate reservoir in Abu Gharadig field, Western Desert of Egypt. It has a good lateral continuity, contains natural fractures with poor connectivity in addition to formation tightness. To further increase the production from the field, a full development plan for Abu Roash-D carbonate reservoir was initiated with drilling of horizontal wells. The main objectives of drilling such horizontal wells was to develop the tight unconventional reservoirs and increase production by dramatically increasing the contact area with the producing interval, maximizing drainage volume around a well and link the natural fractures network thus, achieving an economically production targets.
The effective placement of sufficient acid volume along the open-hole section of such horizontal wells provides significant challenges in acid diversion due to the high permeability streaks that requires a very effective diversion technique for optimal acid distribution a long the open hole lateral for a successful acid stimulation treatment.
A fiber optic enabled coiled tubing attempts to tackle some of these limitations. This new approach deploys downhole sensors with fiber optic telemetry inside the coiled tubing string provides a real time temperature, pressure and correlated depth measurments. The fiber optic telemetry allows distributed temperature surveys recording for obtaining temperature profiles across the entire wellbore. Monitoring the distributed temperature sensing (DTS) profiles accompined with downhole pressure data interpretation enables real time diagnostic of downhole events between the stimulation stages providing an important aid to further optimize and improve the performance of stimulation treatments.
This paper presents case histories of the first time implementation of horizontal wells in Abu Roash-D tight carbonate reservoir in Egypt's western desert in which fiber optic enabled coiled tubing was utilized to optimize stimulation treatment. The real time monitoring of downhole distributed temperature sensing profiles allowed the identification of both high permeability zones as well as tight zones across the entire openhole lateral. This enabled the operator to take pro-active decision on where to spot diverter or acid, select the best diversion technique and allow for treatment optimization.
Salah, Mohamed (Khalda Petroleum Company) | Bereak, Ahmed (Khalda Petroleum Company) | Gabry, M. A. (Khalda Petroleum Company) | Gallab, M. (Khalda Petroleum Company) | Fattah, S. I. Abdel (Khalda Petroleum Company)
Abu Roash-D (AR-D) is a common carbonate reservoir in Abu Gharadig (AG) field, Western Desert of Egypt. It is characterized as a limestone reservoir which has good lateral continuity, contains natural fractures with poor connectivity in addition to formation tightness. The heterogeneity and tightness of AR-D reservoir are the main challenges to maintain economical well productivity.
Initially, Several vertical wells had been drilled in AR-D reservoir and stimulated via matrix acidizing, but could not achieve or sustain the economical target production rates. Recently, two vertical wells were acid fractured as a trial to produce conductive fracture with sufficient length to allow more effective drainage around the wellbore, but test results showed higher flash production of 3,000 BOPD then rapid decline and low recovery occurred. This awesome results encourage embarking on field development and additional production data gathering for development optimization. The large interest in developing such low permeability reservoirs has been a direct result of the favorable economics achieved by the advancements in horizontal well drilling and stimulation technologies hold great promise to increase production by dramatically increasing the contact area with the producing interval, maximizing the drainage volume around a well and link those natural fractures network.
So, In order to economically develop AR-D reservoir resources a comprehensive parametric study was conducted on low permeability AR-D reservoir of western desert (through gathering of additional data during the development a major reservoir, the review of the core and test permeability data across the reservoir as well an evaluation of the uncertainties and associated development risks) has documented some critical results, showing the productivity index ratio between stimulated vertical and horizontal wells illustrates the improvement to be obtained from higher reservoir contact.
This paper takes a multidisciplinary approach to better understand how to enhance the productivity of low permeability AR-D reservoir in Western desert of Egypt through a detailed analysis of well performances and exploitation approaches after the successful Implementation of horizontal wells to maximize drainage volume around the well to revive low producing wells due to reservoir tightness and discuss the actual performance of the horizontal wells and compares them with the offset conventional vertical wells and highlights the productivity gain.
NEAG1 is one of Bapetco fields located in the eastern part of the Western Desert, close to Qarun field. Special Core analysis has been used in an integrated way to optimize parameters used in Static and Dynamic reservoir models. The methodology of selecting the adequate core plugs was an integrated work of PP, PG and RE engineers to ensure optimal selection of samples representative for the reservoir. Routine Core analysis and core photos, logs, SEM were used in the selection procedures.
The results are being integrated into the Static and Dynamic model and they show an improved prediction of reservoir properties.
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.
The JG field is located in the North East Abu Gharadig (NEAG) Basin of the Western Desert in Egypt. With first production in 2002, it is the first commercial discovery in the
Middle Jurassic Lower Safa Reservoir Units in this basin. Oil and gas are produced from the tidally influenced estuary channel deposits in the Lower Safa A Unit and oil from the massive braided fluvial channels in the Lower Safa C Unit.
At first, the field was believed to consist of one single hydrocarbon column. However based on production behavior and additional well information it became apparent that the
field was highly compartmentalized in the vertical and horizontal domain. Since then multiple data sources have been leveraged in order to obtain better compartment definitions: 3D seismic, logs, PVT data, geochemical fingerprinting, repeat pressure surveys and production data.
The boundaries between the reservoir compartments are defined by a combination of faults and stratigraphic heterogeneities. Although clear in places, some compartment
boundaries can only be defined from non-geological data sources. Understanding these heterogeneities and compartment boundaries is essential for optimizing the field development.
Like so many fields the JG field proved to be more complex than initially expected. It is argued that extensive data gathering, in particular in the early field development, is essential in helping to timely identify and properly define such complexities.