The mainly Cenomanian Shilaif formation of Abu Dhabi (UAE) is currently explored and appraised for its shale oil and shale gas potential. The objective is to assess the hydrocarbons resources, the spatial variability of rock and fluid properties as well as highlighting sweet-spots.
The exploration efforts started in 2014, conducting some multidisciplinary regional depositional and petroleum system studies complemented with exploration wells and the acquisition of comprehensive suites of logs, cores and pressured (sidewall) cores.
The Shilaif formation was deposited in a deeper water intrashelf basin and is time equivalent to the adjacent shallow water higher energy Mishrif formation. Non-eroded Shilaif thicknesses vary from 500 to 900 ft from deep basin to slope respectively. The formation can be subdivided into 3-4 composite sequences each with separate source rocks and clean tight carbonates.
The present day structural configuration is inherited from two related regional compressional events; a) a NW-SE compression responsible for the anticline/syncline, lasting from Late Cenomanian to Early Eocene was created by India's continental drift, b) the late Cretaceous (starting in Turonian) emplacement of the Semail ophiolite from NE direction responsible for loading the continental plate and resulting in the creation of a large scale foreland basin. Reactivation of this NE compression occurred during Late Tertiary.
The resulting structuration created two synclines in the south of Abu Dhabi with maximum maturity of 1.1 Vr (TR 0.65). The foreland basin towards the North East has maturity values reaching the dry gas window. The continuous present day stress from a NE direction combined with high overpressures has a strong geomechanical impact with hmin close to overburden in synclinal areas.
This study aims to present the unconventional resource potential of the Late Albian to Early Turonian basinal sequences in Abu Dhabi.
Insights into the local and regional stratigraphic framework as well as structural controls of the depot-centers are presented.
This course provides a fundamental understanding of process safety techniques and how applying these techniques can improve safety, equipment reliability, environmental performance and reduce overall costs. It presents an overview of the elements comprising process safety, practical examples and how process safety can be integrated into day-to-day operations. Working and studying abroad is a huge part of the oil and gas industry and despite the impact on a professional’s career and personal life, little guidance is available for those considering the big move. At this event, we will be sharing stories from those who have gone through the same process and explore some of the benefits and difficulties of diverse working environments. Sustainability means many different things to different people. For governments, it means ensuring development that meets the needs and aspirations of the present without compromising the ability of future generations to meet their own needs.
Africa (Sub-Sahara) Shell has initiated a two-well drilling program in blocks 1 and 4 of the Mafia Deep basin offshore Tanzania. Drilling is taking place in water depths of up to 7,545 ft, with the company and its joint-venture partners Pavilion Energy and Ophir Energy investing almost USD 80 million in the program. The two wells will meet the remaining requirements in the exploration licenses issued by the Tanzanian Ministry of Energy and Minerals. Asia Pacific Petronas has begun gas production from the world's first floating liquefied natural gas (FLNG) facility, the PFLNG SATU, at the Kanowit field offshore Malaysia's Sarawak state. The first-gas milestone marked the onset of commissioning and startup for the FLNG facility, preceding commercial production and initial cargo shipment. The facility is fitted with an external turret for operating in water depths of 229 ft to 656 ft. It will extract gas through a flexible subsea pipeline for the liquefaction, production, storage, and offloading of LNG at the field.
Africa (Sub-Sahara) Eni successfully completed a new production well in the Vandumbu field, 350 km northwest of Luanda and 130 km west of Soyo, in the West Hub of Block 15/06 offshore Angola. The VAN-102 well is being produced through the N'Goma FPSO and achieved initial production of 13,000 BOED. Production from this well and another well in the Mpungi field will bring Block 15/06 output to 170,000 BOED. Anglo African Oil & Gas encountered oil at the TLP-103C well at its Tilapia license offshore the Republic of Congo. The well intersected the targeted Djeno horizon, and wireline logging confirmed the presence of a 12-m oil column in the Djeno. Total started production from the ultra-deepwater Egina field in approximately 1600 m of water 150 km off the coast of Nigeria. At plateau, the field will produce 200,000 B/D.
Carbon dioxide (CO2) has been proven to be an extremely successful enhanced oil recovery method to increase oil recovery from hydrocarbon reservoirs. It has also been proposed as a novel production method for unconventional shale reservoirs with nano pores as well. One of the main drawbacks of CO2 injection is asphaltene precipitation and deposition, which may result in severe pore plugging, and thus a significant decrease in oil recovery. Even though asphaltene precipitation during CO2 injection in conventional oil reservoirs has been researched extensively, not much research has been conducted to evaluate asphaltene precipitation and pore plugging in unconventional nano pores. This research investigates the impact of several factors on asphaltene precipitation and deposition, and asphaltene pore plugging in nano pores. Composite nano-filter membranes with 10, and 100 nm pore size were used to conduct all experiments. A specially designed high pressure high temperature filtration vessel was constructed and utilized to accommodate both the filter membrane, and the crude oil. The impact of varying the CO2 injection pressure, temperature, filter membrane pore size, and the CO2 soaking time on asphaltene deposition, and pore plugging were investigated. Results showed that higher CO2 injection pressures resulted in a higher oil recovery, a lower asphaltene concentration in the unproduced, bypassed oil, and a higher asphaltene concentration in the produced oil compared to the lower CO2 injection pressures. An opposite trend was observed with the temperature however, due to the temperature resulting a severe disturbance in the asphaltene thermodynamic equilibrium with the other crude oil components. Increasing the pore size resulted in a less severe asphaltene pore plugging, whereas increasing the CO2 soaking time resulted in an increase in the asphaltene deposition and pore plugging. This research performs an experimental study to show the main factors that will impact asphaltene precipitation, deposition, and pore plugging in nano pores during CO2 injection. This may help in improving oil recovery from CO2 injection projects in unconventional shale reservoirs, especially those with a high asphaltene percentage in their crude oils.
Kumar, Kamlesh (Petroleum Development Oman) | Awang, Zaidi (Petroleum Development Oman) | Azzazi, Mohamed (Petroleum Development Oman) | Hamdi, Abdullah (Petroleum Development Oman) | Hughes, Brendan (Petroleum Development Oman) | Abri, Said (Petroleum Development Oman)
The microporous rock types in Upper Shuaiba are low permeability ( 1mD) rocks occurring in thin (2-5 m) formations within the extensive Upper Shuaiba carbonate formations in Lekhwair. These microporous rocks constitute a significant volume of hydrocarbon in-place. Unlike the higher quality rudist-rich and grainstone rock types, appraisal pilots in the microporous areas have shown poor performance with waterflood development, which is the preferred development concept in the entire Lekhwair field. Two work streams are active in parallel to identify a technically and commercially feasible development option: Phase 1, technology trials to enable a successful waterflood implementation, and Phase 2, further studies to screen the potential of enhanced oil recovery (EOR) techniques and other light tight oil development. The technology trial work stream, initially considered four initiatives targeting injectivity improvement. To date, trials are complete for abrasive jetting and designer acid stimulation, early results are available for Directional Acid Jetting, and evaluation of Fracture Aligned Sweep Technology (FAST) is ongoing with hydraulic fracturing evaluation accelerated to Phase 1 due to synergies with the FAST evaluation.
In early 80's in ADNOC Onshore standard well completion design for gas producers in Reservoir Y of Bab field was a combination of L-80 carbon steel with a downhole continuous corrosion inhibitor injection above the Chemical Injection Valve (CIV) and Corrosion Resistant Alloy (CRA) Incoloy 825 / SM25Cr-75 below the CIV and packer. In 1994 (after 10 years of operation), due to the fact that no integrity issues were observed, it was decided to maintain the same design strategy was followed in all new gas producer wells in this reservoir. Identical design strategy was followed for Reservoir X (Project-I) gas wells which presented less severe fluid conditions.
The use of Lab NMR, MICP, electrical resistivity measurements and conventional core analysis coupled with petrographic investigations, enabled the authors to understand the pore structure of several carbonate samples and establish a link between pore geometries, Archie's cementation exponent, capillary pressure behavior and NMR T2 response. The lab work was performed on 68 carbonate plugs retrieved from 5 vertical wells completed on a Cretaceous carbonate reservoir, and located at different structural positions (from crest, mid-flank and down-flank areas), capturing different hydrocarbon column heights and, therefore, different degrees of diagenesis and porosity degradation. The equipment used was Magritek 2MHz NMR Rock Analyzer for the T2 distributions, Micromeretics for MICP, Pantera for the ambient resistivity measurements and PORG-200TM for the conventional core analysis. The petrography was done using conventional polarized light microscope. From the combined analysis of NMR T2 spectrum and electrical resistivity measurements we concluded that the magnitude of the Archie's cementation exponent "m" is greater when the samples exhibit variability within the largest pore class ranges (meso to macro scale) than on the smaller pore class range (micro to meso scale).
More than 80% of Abu Dhabi oil reserves are accumulated in the Thamama reservoirs. However, its source rock locations, thickness and richness distributions are not fully understood.
Thamama hydrocarbons were generated and migrated from different source rocks including Diyab, Rayda, Thamama dense and Shuaiba basinal facies, in addition to a contribution from the deeper Paleozoic, Silurian Qusaiba and the Pre-Cambrian Huquf source rocks.
The Oxfordian, Diyab high-energy Oolitic belts are prograding in westward direction, and have resulted in the development of Diyab intrashelf basin in west Abu Dhabi. At the end of the Kimmeridgian time, Abu Dhabi basin was tilted towards the east due to the opening of Arabian-Indian Suture. This tilting had completely shifted the high-energy Oolitic belts to prograde in eastward direction, which resulted in the development of Rayda source rock in east Abu Dhabi.
The Thamama dense layers were deposited during the highstand system tract, which allowed some organic matter to be preserved; especially in intervals deposited below the wave base. The Shuaiba basinal facies were deposited in an intrashelf basin that was surrounded by the Shuaiba shelf facies. This resulted in restricted water circulation and anoxic conditions. Such depositional environment is reasonable for source rock preservation.
The hydrocarbon generations from these different sources were mainly accumulated in a super-giant Paleo-structure that was located in the northeast onshore Abu Dhabi. This Paleo-structure was segmented by the Late Tertiary tilting, which resulted in remigrating its trapped hydrocarbon into the prominent Abu Dhabi fields.
The development of Rayda source rock will increase the potentiality of finding additional unconventional hydrocarbon resources in east onshore Abu Dhabi. The high unconventional potential in this area can be attributed to the advanced level of source rock maturity and to the highly faulting and fracturing found in east onshore Abu Dhabi. The Rayda source rock maturity map confined the unconventional gas potential to the foreland basin while the unconventional oil potential is located to the south of this area (
Understanding the locations of Thamama source rock kitchens will facilitate the delineation of its migration pathways. This will reduce the exploration risk and help in detecting prospective areas for stratigraphic traps potential along the Thamama migration pathways over all Abu Dhabi.
In line with our quest to improve performance, optimize efficiency, and increase profitability, ADNOC Gas Processing is committed to ensure process design optimization by following best practices that add significant value to its gas business and industry. This report will outline how we were able to increase our C3+ recovery and thus the NGL production of BuHasa Train 2 by safely utilizing the existing design envelope and available design margins.
Although, operating a plant beyond its design capacity is not a new concept, process and HSE assessments are a must before proceeding. These efficiency enhancements can be implemented without any capital investment and also strengthen a plant's readiness to deal with any future challenges in plant performance. In gas processing plant such as NGL extraction, process fluid pressure is an important factor which can affect the plant characteristics. The influence of different values of pressure drop in various equipment needs to be realized as it can affect the quality and quantity of the process outputs.
An in-house feasibility study has been conducted to evaluate the possibility of increasing the HP compressor discharge pressure by 1 bar over its current operating pressure. The study indicated that it was possible to enhance the train's efficiency by increasing C3+ recovery, leading to an increase in NGL production and therefore a profitability increase.
The study was completed after the plant facilities were comprehensively evaluated for process safety and operability, as well as analyzed improvements in terms of C3+ recovery and NGL production.
A successful "Field Test Run" for 10 days were conducted to validate the predictions of the study to operate the HP compressors at 1 bar higher.
The product specification, quantity and plant operating costs are important parameters and balancing them will determine the optimum pressure distribution in the process and consequently realize our benefits. Hence, during the test run, the revised operating conditions were implemented and achieved safely without any major modification or upset to the facilities. As a result, the following cost benefits were realized: C3 + Recovery increased by around ≈ 0.2 wt.% NGL production increased by around ≈ 35 Ton/day Revenues increased by around ≈ 2.8 MM US$/Year Operating cost increased by around≈ 220000 US$/Year
C3 + Recovery increased by around ≈ 0.2 wt.%
NGL production increased by around ≈ 35 Ton/day
Revenues increased by around ≈ 2.8 MM US$/Year
Operating cost increased by around≈ 220000 US$/Year