Abdullatif, Osman (King Fahd University of Petroleum & Minerals) | Osman, Mutasim (King Fahd University of Petroleum & Minerals) | Yassin, Mohamed (King Fahd University of Petroleum & Minerals) | Makkawi, Mohamed (King Fahd University of Petroleum & Minerals) | Al-Farhan, Mohamed (King Fahd University of Petroleum & Minerals)
The Miocene deep sea turbidite sandstone of Burqan Formation is important hydrocarbon reservoir target in Midyan region, Red Sea, NW of Saudi Arabia. Excellently exposed outcrops of Burqan Formation in Midyan region provide good data to examine and evaluate the reservoir rocks. This study integrates field observations (sedimentologic, stratigraphic and structural) and measurements from outcrop analog of the turbidite sandstone to investigate and characterize the reservoir heterogeneity, quality and architecture. The methods and approach followed used sedimentologic and stratigraphic analysis based on vertical and lateral outcrop sections and photomosaic so as to reveal the vertical and lateral distribution of the lithofacies and their geometries at outcrop scale. Moreover, terrestrial laser scanning (LiDAR) was utilized in this study to capture outcrop meso to macroscopic sedimentologic and stratigraphic and structural features details (strata surfaces. geometry distribution, faults, fractures). We integrated field observations with laboratory analyses to characterize the microscopic sedimentologic heterogeneity of lithofacies, texture, composition and petrophysical properties of the turbidite sandstone.
The stratigraphic analysis shows variation in outcrops from proximal to distal parts, within 15 to 20 km traverse across the outcrops belt (west to east) of Burqan Formation. The sandstone body thickness varied between 2 – 4 m in the proximal parts and between 0.5 – 1 m distally. Also, these variations in thickness was associated with increasing of shale/sandstone ratio from proximal to distal parts. The sandstone bodies width revealed from outcrop mosaics extend laterally between 100 to over 150 m. The lithofacies consists of both matrix and clast supported conglomerates, pebbly sandstone and coarse to very coarse and medium grained, massive, trough and horizontally stratified sandstone. These facies were interbedded with siltstone, mudstone and shale. The sand bodies were vertically and laterally stacked in the proximal parts and decreases in the medial and distal parts, however, locally the shale and mudstone lithofacies interbeds and form baffle zones. The region is tectonically and structurally active, therefore, at outcrop scale the repeated tectonics and rifting in the region resulted in faulting, shearing and fracturing which added complexity to the turbidite sandstone reservoir architecture. Moreover, tectonic affected reservoir/seal relationship, reservoir continuity and distribution of inter-reservoir barriers and baffles.
The results of this high resolution outcrop analog study might provide information and data base on types and scales of geological heterogeneities and their impact on reservoir quality and architecture within the interwell spacing. Moreover, it might also provide guides for exploration and development and help in decision making to avoid risks under the complex geological setting in the Red Sea region and other hydrocarbon basins under similar geological setting.
By International Petroleum Technology Conference (IPTC) Monday, 25 March 0900-1600 hours Instructors: Olivier Dubrule and Lukas Mosser, Imperial College London Deep Learning (DL) is already bringing game-changing applications to the petroleum industry, and this is certainly the beginning of an enduring trend. Many petroleum engineers and geoscientists are interested to know more about DL but are not sure where to start. This one-day course aims to provide this introduction. The first half of the course presents the formalism of Logistic Regression, Neural Networks and Convolutional Neural Networks and some of their applications. Much of the standard terminology used in DL applications is also presented. In the afternoon, the online environment associated with DL is discussed, from Python libraries to software repositories, including useful websites and big datasets. The last part of the course is spent discussing the most promising subsurface applications of DL.
The Gulf of Suez Basin (GOS), a World Class Hydrocarbon Province, is a typical Continental Rift, but many perplexities arise from the different proposed evolutionary models.
Previous models describe extension along (N)NW-(S)SE faults with antithetic half grabens, but show numerous difficulties to capture all observed elements into one single frame, as reconstruction is hampered by low seismic resolution below the heterogeneous Upper Miocene salt. Our analyses (from outcrop, seismic, well logs, gravimetry, magnetometry, dipmeter, and seismic and magnetic reprocessing), over the last years, allows the definition of a new tectonic model better describing these features: The GOS evolution is placed in a sinistral transtensional regime, reinterpreting the Duwi (WNW-ESE), Clysmic (NW-SE), Aqaba (NNE-SSW), and Cross (NE-SW) trends and the two (twist) accomodation zones, showing two distinct episodes resulting in overprinting of differently trending and tilting fault blocks. Furthermore it tackles perplexities related to the link between subsidence amounts/rates (backstripping), and extension, strain distribution, and episodes/pulses/unconformities. It describes the increase in extension towards the south in the rift-sphenochasm, and resolves the enigmatic relationship between high angle faults (that dominate the area), low angle dipping older faults and rotated pre-rift successions.
Our model foresees a two staged evolution: Initial rifting (Early Miocene - E1; Abu Zenima, Nukhul, Rudeis series) occurred along WNW-ESE trending (Duwi) faults disposed in an en-echelon manner as a result of a sinistral transtension. These faults progressively rotated in some areas towards a low angle with accompanied high angle "antithetic" tilted pre-rift strata. Subsidence accelerated during the Early Miocene, and some of these tilted fault blocks show erosion surfaces partly related to the final Early Miocene tectonic pulse. In a second stage (Mio- Pliocene - E2; Kareem, Belayim series, South Garib salt, Zeit evaporates) this pattern is overprinted by a new set of high angle rift faults trending (N)NW-(S)SE (Clysmic) cross-cutting the previous faults, but without any major block rotation. The Late Pliocene-Pleistocene (E3; Post Zeit, Shulher series) large (accelerating) differential uplift and subsidence, shows "synthetic tilting" of the strata along the rift margins, local tectonic inversion, syn- sedimentary detachment along the mobile salt layer with the generation of en-echelon ridges, generating the present day complex fault pattern (sigmoidal intervening trends and cross trends), and differently tilted smaller fault blocks. The new model is fully compatible with the pulsating NNE-NE movement of the Sinai Plate, associated with the NE moving Arabian Plate and Red Sea rifting, and has severe consequences for further Exploration and Development in the GOS, as it describes the configuration of the Hydrocarbon Fields in a more comprehensive way and predicts the occurrences of undiscovered Prospects.
Sandoval-Curiel, Ernesto (Geophysics Technology, EXPEC Advanced Research Center, Saudi Aramco) | Colombo, Daniele (Geophysics Technology, EXPEC Advanced Research Center, Saudi Aramco) | Rovetta, Diego (Geophysics Technology, EXPEC Advanced Research Center, Saudi Aramco) | Turkoglu, Ersan (Geophysics Technology, EXPEC Advanced Research Center, Saudi Aramco) | Al-Najjar, Mohammed (Geophysics Technology, EXPEC Advanced Research Center, Saudi Aramco) | Kontakis, Apostolos (Geophysics Technology, EXPEC Advanced Research Center, Saudi Aramco)
Conventional velocity model building utilizes migration velocity analysis (MVA) to obtain the most accurate distribution of velocities for imaging. This is typically done in layer-stripping with interpretation support by migrating the seismic data with the best available estimate of interval velocities, analyzing the residual move-out after migration, and converting the kinematic errors into velocity updates. Several iterations of horizon interpretation, move-out picking and reflection tomography are typically needed where artifacts can be introduced in the velocity distribution if the signal-to-noise ratio is low. We developed a novel refraction analysis method to robustly derive in an automatic way the shallow velocity distribution. The key aspect of the method consists of the introduction of a common hyper-dimensional sorting domain for refracted waves consisting of midpoint-offset where travel time-offset functions are evaluated to automatically derive velocity-depth profiles. The process is entirely data driven and does not require a starting model. The methodology is demonstrated on three complex 3D marine datasets where it provides imaging results comparable to extensive velocity model building workflows.
Presentation Date: Monday, October 15, 2018
Start Time: 1:50:00 PM
Location: Poster Station 16
Presentation Type: Poster
The seismic data set provides geological information from stratigraphic boundaries. Commonly, different responses are reflected in terms of amplitude, phase and frequencies changes. The bandwidth of the seismic signal and processing approximations restrict the subsurface resolution. Several techniques such as seismic inversion, spectral decomposition, coherency processing has been developed to extract geological information from the seismic data, to reveal the subsurface geology and evaluate reservoir targets. This work summarizes different workflows to improve seismic imaging and provide better reservoir characterization of carbonate buildups in the Red Sea. The process started in terms of whether the seismic attributes below the salt are robust enough to enable a seismically driven carbonate characterization. Extensive gather analysis, velocity corrections and data conditioning was performed at pre and post stages. Employing HD spectral decomposition, elastic inversion, interactive geobody extraction and integration of well data (core analysis) a successful qualitative and quantitative reservoir characterization was reached.
Predicting heat flow in constrain modeling of a petroleum system in the Red Sea is a significant exploration challenge. In this study, we developed an integrated workflow to utilize seismic, magnetic and gravity data in the offshore Jazan area of the Red Sea to build a crustal model and to identify crustal type. Depth to Curie temperature was estimated from magnetic data and used together with thermal properties of the rocks to predict present-day heat flow for the interpreted crustal model. The predicted heat flow shows a generally increasing trend toward the rift axis due to an elevated asthenosphere boundary that is consistent with a thinned crust model. The model of thinning continental lithosphere and predicted heat flow derived from the integrated workflow provides valuable constraints to reduce the uncertainties in basin modeling.
Witte, Jan (Falcon Geoconsulting) | Trümpy, Daniel (DT EP Consulting) | Meßner , Jürgen (Federal Institute for Geosciences and Natural Resources ) | Babies, Hans Georg (Retired from Federal Institute for Geosciences and Natural Resources )
Several wells have encountered good oil shows in the rift basins of northern Somalia, however, without finding commercial hydrocarbons to date. It is widely accepted that these basins have a similar tectonic evolution and a comparable sedimentary fill as the highly productive rift basins in Yemen from which they have been separated by the opening of the Gulf of Aden (fully established in Mid Oligocene). We present new regional tectonic maps, new basement outcrop maps, a new structural transect and new play maps, specifically for the Odewayne, Nogal, Daroor and Socotra Basins.
Digital terrain data, satellite images, surface geology maps (varying scales), oil seep/slick maps, potential data (gravity), well data from ~50 wells and data from scientific publications were compiled into a regional GIS-database, so that different data categories could be spatially analyzed.
To set the tectonic framework, the outlines of the basins under investigation were re-mapped, paying particular attention to crystalline basement outcrops. A set of play maps was established. We recognize at least three source rocks, five reservoirs and at least three regional seals to be present in the area (not all continuously present). Numerous oil seeps are documented, particularly in the Nogal and Odewayne Basins, indicative of ongoing migration or re-migration. Data from exploration wells seem to further support the presence of active petroleum systems, especially in the central Nogal, western Nogal and central Daroor Basins.
Our GIS-based data integration confirms that significant hydrocarbon potential remains in the established rift basins, such as the Nogal and Daroor Basins. Additionally, there are a number of less known satellite basins (on and offshore) which can be mapped out and that remain completely undrilled. All of these basins have to be considered frontier basins, due to their poorly understood geology, remoteness, marketing issues and missing oil infrastructure, making the economic risks significant. However, we believe that through acquisition of new seismic data, geochemical analysis, basin modelling and, ultimately, exploration drilling these risks can be mitigated to a point where the economic risks become acceptable.
We encourage explorers to conduct regional basin analysis, data integration, a GIS-based approach and modern structural geology concepts to tackle key issues, such as trap architecture, structural timing, migration pathways and breaching risks.
The rheological properties of drilling fluids are crucial parameters in offshore operations, especially in the extreme conditions encountered during deepwater drilling. Oil based muds (OBM) are almost exclusively used in deepwater drilling operations, owing to such factors as their improved temperature stability, effectiveness when drilling through water sensitive formations, and capability to be utilized in narrow-margin drilling. A desired property of the drilling fluid is a minimal sensitivity of the flow properties with respect to temperature, leading to a flat-rheology system. Chemical additives provide the basis for the fluid's rheological properties, but are rarely addressed in detail within published literature. This paper reviews the chemistries of existing additives and their claimed uses. In addition to addressing the current state of the art, results are presented from an investigation into the effects of such emulsifier chemistries upon the rheological properties of the drilling fluid. This includes work on a novel emulsifier and comparative data to an industry standard incumbent. Through an improved study of the chemistry, a design-based approach can lead to the development of optimal properties for these high performance invert emulsion drilling fluids.
The unconventional boom that has swept across North America over the past decade is a testament to how game-changing technology combined with expanded knowledge and understanding has transformed the paradigm of hydrocarbon production. Ongoing development of horizontal drilling and completion technologies and sophisticated downhole logging tools have been instrumental in increasing efficiency to make oil and gas shale plays economically viable. Today, more than 70,000 horizontal wells are producing from unconventional resource plays with massive, multistage fracturing campaigns.
Over the years, however, operators have learned that reservoir heterogeneity and low-permeability rock present challenges that can limit the potential of unconventional development. Despite the fast pace of technological advances, production log analyses reveal that conventional completion designs, including the practice of placing perforation clusters evenly along the lateral, may not be the best approach to production in these plays. Production logs show that on average, 40% of the perforation clusters in a given lateral are not contributing to production.
Unconventional wells also exhibit rapid declines from initial production (IP) rates, sometimes by as much as 60% to 80% during the first year of operation. If early IP rates are not managed, or choked, properly, subsequent steep declines can cause long-term damage to the fracture conductivity.
As the industry faces new challenges in the wake of low commodity prices and a slowdown in drilling, it is eyeing a significant new opportunity to take unconventional resource development to the next level: refracturing. While refracturing of the Barnett Shale generated interest in 2008–2009, the development of new diversion technologies is enabling oil and gas operators to once again consider refracturing as an economic alternative to drilling new wells.
While producers are still working to understand the mechanisms of unconventional production and how wells behave and flow, they do have a much better understanding of the subsurface than they did in the early days of a play as more wells have been drilled and data collected from these wells are pieced together. At the same time, fracture models for determining optimum treatment designs and technologies that can divert treatments to new unstimulated rock are now available and proven.
This enhanced reservoir understanding and access to technology are incentivizing operators to take a second look at refracturing as a feasible and cost-effective alternative to drilling new wells. By reinvigorating existing, often depleted, assets, companies can enhance hydrocarbon recovery while boosting cash flows.
A Unique Consortium
Refracturing also provides the added benefit of protecting the depleted wells from the negative effects associated with fracture hits when drilling offset wells. Companies historically have encountered production losses from “parent wells” when an infill fracture interferes with the depleted well. By refracturing the depleted wells before fracturing the infill well, operators have successfully prevented these negative impacts and actually experienced improved production from both the infill and depleted wells.
In 2014, Schlumberger assembled a team of experienced geoscientists from the hydraulic fracturing and reservoir subsurface disciplines to determine the criteria for developing a workflow to diagnose potential well candidates for refracturing. The team formed a consortium with several of the most active operators in the oil- and liquids-rich Eagle Ford Shale. Members of the consortium are providing the necessary data to define wells, most of them 1 to 4 years old, which would be good refracturing candidates in the play. By joining forces in this unique study, the consortium members are creating a critical mass of data, with the results of the well studies shared among the companies. This has facilitated accelerated learnings and best practices in well candidate selection and refracturing design.
The area of study covers the trough and the eastern flank of the Gemsa basin, which is located in the southwestern onshore part of the Gulf of Suez. Bad quality of traditional 2D seismic data and following classical exploration concept of drilling structural highs were resulted in several dry holes and hence, the area suffered from lost hydrocarbon interest for several years. Recently acquired 3D seismic data progressed the imaging of deeper hanging wall structures and improved the understanding of the area. Changing the exploration concept by drilling hanging-wall traps resulted in few oil fields discoveries and revived the further exploration efforts in the area. This work is an attempt to realize the hydrocarbon trapping mechanism and the main controlling factors of reservoir distribution in the study area through seismic data interpretation and analysis of borehole data in an integration with the surface geology. The main reservoir in the study area is represented by thin sandstone intervals of Middle Miocene age imbedded in a thick shale and marl section of the Kareem Formation. This formation is sporadically cropping-out in the hogback of the prominent Gebel El Zeit ridge before its submergence due SW for a depth of 14,000 feet in the trough of the Gemsa basin. This major subsidence in a distance of around 8 kilometers was accessed by a complex fault system.