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.
Choudhary, Manish (Shell Technology Center) | Nair, Saritha (Shell Technology Center) | Pal, Sabysachi (Shell Technology Center) | Munimandha, Amuktha (Shell Technology Center) | Kohli, Abhinandan (Shell Technology Center) | Nirmohi, Samiksha (Shell Technology Center) | Gupta, Shyam (Shell Technology Center) | Jain, Sid (Shell Technology Center)
Integrated analysis of data together with fit-for-purpose modelling can help in fast track maturation of opportunities. In 2012, an opportunity to increase oil by implementing waterflood was identified, and last year was further reviewed by Shell. An integrated approach helped the team to mature ten development wells within three months which were subsequently drilled and helped the operator to surpass their production targets.
The field located in Western Desert, Egypt comprises of an Upper Cretaceous tidal channel system across four key reservoirs where sand thickness ranges between 2-15 m. Large uncertainties in reservoir extent, architecture and properties required the integration of data across multiple disciplines for identifying new development wells.
It was recognized early on that the construction of full-field fine-scale static models would be time-consuming and hence a simplified fast-track approach was used for maturing the opportunity. Conceptual depositional models were built by integrating dipmeter data, image logs and core facies descriptions to understand the direction of continuity of tidal channels, tidal bars and mud flats.
Net sand thickness maps were then constructed to represent the conceptual depositional model and integrated with the production behaviour of the wells. Production from historical wells drilled up to 2012 caused non-uniform pressure depletion across reservoirs. The pressure data from Modular Dynamic Tester (MDT), along with the production-injection history, was reviewed to identity both areal and vertical stratigraphically connected areas which were incorporated in the net sand maps. The constructed maps were quality checked with pressure and production data so as to validate the range of in-place volumes. Net sand maps, porosity maps and saturation models were combined to generate Hydrocarbon Pore Volume (HCPV) maps used to identify new well opportunities.
Separate sector models were also constructed to evaluate the waterflood and to optimise the decision parameters like injector-producer spacing, injection rates, voidage replacement ratio and target reservoir pressure. A range of type curves were generated from Monte Carlo simulation runs for all key sub-surface uncertainties then was used to estimate the low, base and high case recoverable volumes for the identified well locations and patterns.
The identified wells were drilled between February and August 2015 and helped increase production rates of the field by over 5,000 stb/d.A fit-for-purpose modelling using sand maps and connectivity maps can often greatly help in fast-tracking opportunity maturation and fine-scale detailed simulation modelling may not provide additional value.
Mallick, Tanmay (Shell India Markets Private Limited) | Garg, Ashutosh (Shell India Markets Private Limited) | Choudhary, Manish (Shell India Markets Private Limited) | Nair, Saritha (Shell India Markets Private Limited) | Pal, Sabyasachi (Shell India Markets Private Limited) | Jana, Debadrita (Shell India Markets Private Limited) | Singh, Abhinav (Shell India Markets Private Limited) | Goudswaard, Jeroen (Shell India Markets Private Limited) | Faulkner, Andrew (Shell India Markets Private Limited) | Salakhetdinov, Ravil (Shell India Markets Private Limited)
A new seismic and quantitative reinterpretation was carried out for a brownfield in Western Desert, Egypt to improve depth predictability, de-risk appraisal well locations and to better understand producer-injector connectivity.
The study field is located in the Western Desert, Onshore Egypt and comprises of Upper Cretaceous tidal channel systems across four key reservoir levels where sand thicknesses range from 2 to 15 m. The field was discovered in 1993 but development drilling only commenced in 2008. The last integrated field study was performed in 2012. The analysis of wells drilled post-2012 indicated that there is a considerable depth difference along the flanks of the structure between seismic predicted depths and actual well tops (>50 m). The fault interpretation also required a re-look so as to reduce the lateral uncertainty of the main boundary fault and explain the lack of injection response in some areas of the field. This necessitated an update of seismic interpretation, static and dynamic models. A new interpretation could help identify attic volume upsides and help mature new appraisal and producer-injector locations. Further work was also proposed to test the feasibility of using seismic inversion for facies discrimination.
The available Pre-Stack Depth Migration (PreSDM) data was re-interpreted as part of the project. The fault interpretations were quality checked using Semblance/Dip maps, sand box models and wherever possible, were tied to the fault cuts seen in previously drilled wells. The time horizon correlation and seismic polarity were verified and were also cross-checked with the P-Impedance volume before being used in the static modelling workflow. The PreSDM Interval velocity model was used for depth conversion, where an anisotropy correction was applied to tie the wells. Vok and Polynomial methods were also applied, which in turn were used to derive depth uncertainty estimates. The update in the main bounding fault interpretation generated new appraisal locations in the deeper levels. The new interpretation was tested against the results from the latest drilling campaign in the field, and nine out of ten wells were within the one standard deviation uncertainty range.
Simultaneous inversion of the seismic data was also carried out as part of the project using the acoustic, shear and density data from 6 wells over the field. The inverted P-Impedance and S-Impedance were converted to Net to Gross (NtG), and were checked against the remaining 24 wells, which helped in validating the property cubes.
Forward wedge modelling suggested that individual sands of less than 15 m thickness would not be resolved from seismic due to seismic bandwidth limitations. Still, a review of inversion data together with geological insights and dynamic data helped to identify the high NtG areas across the reservoirs.
The integrated interpretation of inverted volumes with well and production data resulted in new insights into the field and helped to mature new appraisal and development well locations.
Stock Tank Oil Initially in Place (STOIIP) uncertainty have been raised recently as a major impact on development plans of mature oil fields under the current tough economic conditions. One of the most complex reservoirs in Gulf of Suez is the Nezzazat group that has a high degree of lateral and vertical heterogeneity. Reservoir productivity and injectivity of such heterogonous reservoir require a high quality 3D geo-cellular model and a robust dynamic history match. However, the intersected lobes of bars and channels of in such heterogeneous concealing underneath a thick salt succession are very difficult to interpret and therefore impose a profound integrated study. This involves petrophysical characterization of Nezzazat group into seven hydraulic flow units honoring the lithostratigraphy of the basin, Mattula, Wata and Raha formations. To enhance field development plan, the Big Loop simulation approach is applied to cover all the existing geological uncertainty. This model honors the available dynamic data including static reservoir pressure, repeat formation tester data, injection and production logs in both history matching and prediction phases.
The 3D dynamic simulation model achieved history match to the seven reservoir intervals using RFT pressure data and production logs on layer basis, showing a wide range of permeability and contribution. The history matched model has successfully proved that the dynamic STOIIP is higher than the previous volumetric STOIIP with additional ±7 MMBO. This opened a window towards drilling new well to increase the current recovery factor for the field and achieve the new ultimate recovery. Therefore, the proposed methodology not only checks the validity of volumetric STOIIP calculations but also helps understanding hydraulic flow units architecture under uncertainty to increase the ultimate recovery of the mature fields.
How can you achieve 20% well costs reductions with no flexibility on wellheads, casings or completion…and two months to do it. Impossible? In Bapetco we said: "Why not?" and we took on the challenge.
This paper tells the story of the first cemented completion executed in Egypt. It describes how Bapetco engineered and executed a cemented completion program in 46 days from concept to rig release. Achieving
With limited time to develop a well concept, the processes need to be scaled down. To achieve this, an organization needs to ensure high levels of communication and team work.
For Sitra Cemented Completion, the story starts with the idea of cementing the completion to reduce well costs. This concept was endorsed during our
It was then up to the well engineers to design a cost effective well to deliver this 4 ½" cemented completion. It was clear to us: the way to cut costs and remain effective was to drill small and fast.
The biggest limitation to drill a Slim well was the lack of fit for purpose wellhead equipment. So we went out of the box. We re-engineered the conventional well and the casing depths to allow the well to be finished in 6". It was not the perfect solution, but perfect is the enemy of effective. For this pilot project, the compromised solution would allow us to test the concept and save costs on iron, fluids, bits and time.
None of this can be achieved without all groups deeply engaged, without communication, empowerment and, in some cases, compromises for the greater good.
Two wells have been drilled. Both drilled as
This study discusses the depositional setting of the Upper Cretaceous clastic dominated Abu Roash G reservoirs of Cenomanian age which deposited during in an overall transgressive setting continued into the Turonian and reached culmination in the deposition of the overlying Abu Roash F limestone as a clear regional marker.
Abu Roash G is divided into two main units, Upper & Lower Abu Roash G separated by the transgressive surface represented by the Intra Abu Roash G limestone which is easily to be tracked allover Abu Gharadig basin. Each of the Upper or the Lower Abu Roash G units has more than one sand reservoir unit.
This study tries to construct a paleogeographic model for each of the sand units of Abu Roash G in Alam El Shawish area. The interpretation was derived from wireline logs, Image, seismic attributes, depositional regimes & the experience absorbed from the nearby areas in Abu Gharadig basin using calibrated correlation / sequence stratigraphic framework through detailed core based facies.
The sea level oscillation had a profound influence on sedimentation of Abu Roash??G?? Member in Alam El Shawish area. Abu Roash "G?? Sandstone reservoir provide a good case history for coastal setting & believed to be exhibit both regressive and transgressive trends. This is related in lateral changes in distribution of sandstone from tidal channel, tidal flat, and barrier bar to tidal bar cross Alam El Shawish fields & vertical change through the time.
According to the integrated vision of the geological & seismic data that always add value to any prospect, field, or basin, seismic attributes computed from the 3D seismic data set proved useful in relating different reservoir characteristics interpreted from well data. These attributes were merged into the geological models & provided a description of the porosity distribution in Bahga field.
This study discusses the Upper Cretaceous clastic dominated Abu Roash G depositional environment. Abu Roash G formation comprises of two main sand reservoirs which are producing from different areas in Western Desert. Alam El Shawish fields are of these areas located directly to the East of Sitra field (Fig: 1) therefore this study is a trial to create a conceptual depositional model for these reservoirs of Abu Roash G formation. This study concentrated on Bahga & Al Assil fields as they have sufficient geological data to interpret sedimentary features & also they are located at different distances from the expected general trend of the shore line (E-W trend) as Al Assil field is located to the north of AESW area & Bahga to the south & this issue can benefit us to follow the lateral change in the depositional environment from the distal to the proximal parts.
This paper demonstrates how a holistic modeling approach and multidisciplinary integration were used to plan the longer-term development of a recent, promising discovery.
The Sitra field was discovered in 1983. Three subsequent appraisal wells discovered additional reservoirs. The wells also demonstrated that sand prediction and lateral connectivity would be a dominant challenge to field development. .
A joint SENV/BAPETCO/EPTS multi-disciplinary project was initiated to help plan the further appraisal and development of the field. The static model was to become the backbone of the subsurface work. The model had to be useable for both immediate and longer term field development planning and had to fulfill the requirements of various departments.
Well engineering safety guidelines required the conservative 3D rendition of the main bounding fault. Petroleum engineering required the most realistic structural model for the main area of the field and boundary fault.
In the main reservoir, multi-disciplinary integration played a key role in the construction of the geological model. The background was provided by a recent regional study. AVO inversion provided results that could only be used qualitatively, but a seismic Stratigraphic interpretation integrated with sequence Stratigraphic well correlation and sedimentlogical core description did indicated the potential presence Tidal Channel/Bar system which fit in the context of all other subsurface data. The resulting conceptual model is of an Delta/Submarine depositional system in which high quality channel sands are concentrated in two NNE-trending systems. The 3D Facies model was constructed accordingly.
This static model was fully history matched and used to forecast alternative development scenarios for this Oil/Gas reservoir, providing a strong basis for future reserves reassessments.
Integration across disciplines, organizations and locations was critical in project delivery. The common 3D Grid helped in sharing information between different teams and reinforced cooperation. Remote working tools were important in the transfer, handover and sharing of information and models.