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Medhat (Med) Kamal, who will be the 2023 SPE President, is a Chevron Fellow Emeritus with primary responsibilities including competency development within the company, identification and development of emerging and white-space technology opportunities, and provision of technological advice and counsel to senior management. He formerly was a fellow and leader at the dynamic reservoir characterization group for Chevron Energy Technology Company. Before Chevron he worked for ARCO, Flopetrol Schlumberger, and Amoco. He holds master's and doctorate degrees in petroleum engineering from Stanford University, and a bachelor's degree in petroleum engineering and a master's in engineering from Cairo University.
Andrew L. Smith, SPE, is a risk consultant in Aberdeen. He holds a BS degree in applied chemistry from De Montfort University and a PhD degree in organic chemistry from the University of Manchester Institute of Science and Technology. Smith's career spans 50 years of international executive leadership in health, safety, security, environment, and social responsibility; integrated risk; and life-cycle management gained in engineering, fabrication, construction, commissioning, operation, maintenance, and decommissioning projects associated with the global chemical, petrochemical, and oil and gas industry in South America, Europe, South Africa, the Middle East and Southeast Asia. He is a member of SPE's Health, Safety, and Environment Technical Director's Advisory Committee and a standing member of SPE's Distinguished Lecturer Committee. Smith was an SPE Distinguished Lecturer in 2010–2011.
Shell informed Tunisian authorities in May it will hand back upstream concessions and leave the country next year as it turns its focus to renewable energy, according to a Reuters report sourcing a senior official in the country's energy ministry. The license in question is the Miskar concession in the southern city of Gabes. The operator has also requested the early hand-back of the Asdrubal permit, which expires in 2035. Recent reports suggest the operator may be looking for the Tunisian government to extend its permit on the field under more favorable terms ahead of its planned departure.
Pockets of shale gas were encountered during test drilling in the semi-desert Karoo region of South Africa, according to the nation's energy ministry. A total of 34 gas samples had been bottled and taken to laboratories after the government's Council for Geosciences set out to drill a 3500-m stratigraphic hole in the Karoo to establish and test the occurrence of shale gas. "The first pocket of gas was intercepted at 1734 m with a further substantial amount intercepted at 2467 m spanning a depth of 55 m," said Gwede Mantashe, South African energy minister, during his budget vote in parliament on 18 May. In 2017, geologists at the University of Johannesburg and three other institutions estimated the gas resource in the Karoo was probably 13 Tcf. Earlier, the US Energy and Information Administration estimated the Karoo Basin's technically recoverable shale-gas resource at 390 Tcf, then making it the eighth largest in the world and second largest in Africa behind Algeria.
A new subject in the area of personnel and equipment security has appeared in the late 1990s. Conditions in the Middle East, West Africa, and areas around the world with radical religious sects have required operators and drilling contractors to take security steps not envisioned just 10 years ago. Because overseas operations usually involve air flights for personnel, sometimes into hostile countries, use of security consultants and constant contact with local governments and intelligence agencies are now common.
The International Gas Union's (IGU) recent report on world LNG markets found that the trade increased by only 1.4 mt to 356.1 mt compared to 2019 supported by increased exports from the US and Australia, together adding 13.4 mt of exports. Asia Pacific and Asia again imported the most volumes in 2020, together accounting for more than 70% of global LNG imports. Asia also accounted for the largest growth in imports in 2020--adding 9.5 mt of net LNG imports vs. 2019. While 20 mtpa in liquefaction capacity was brought on stream in 2020, all in the US, startup of several liquefaction trains in Russia, Indonesia, the US, and Malaysia were delayed as a result of the pandemic, according to the report. The only project that was sanctioned in 2020 was the 3.25-mtpa Energia Costa Azul facility in Mexico, and in early 2021 Qatar took final investment decision (FID) on four expansion trains totaling 32 mtpa.
Natural gas has begun flowing from the BP-operated Raven field, the third stage of the company's major West Nile Delta (WND) development off the Mediterranean coast in Egypt. The $9-billion WND development includes five gas fields across the North Alexandria and West Mediterranean Deepwater offshore concession blocks in the Mediterranean Sea. Raven is currently producing approximately 600 MMcf/D with a peak potential of 900 MMcf/D and 30,000 B/D of condensate. Raven follows the Taurus/Libra and Giza/Fayoum projects, which started production in 2017 and 2019, respectively. It produces gas to a new onshore processing facility, alongside the existing WND onshore processing plant. In total, the WND development includes 25 wells producing gas to the onshore processing plant via three long-distance subsea tiebacks.
Abstract On a Deep Gas Field in the Middle East, it is required to drill across a highly fractured and faulted carbonate formation. In most wells drilled across the flank of this field, it is impossible to cure the encountered losses with conventional or engineered solutions. Average time to cure losses is 20 days. With the current drive for cost optimization, it has become necessary to eliminate the NPT associated with curing the losses. A thorough risk assessment was conducted for wells drilled on the flank of this field, it was established that the risk of encountering total losses was very high. Seismic studies were performed and it was observed it would be impossible to eliminate total losses as fractures were propagated in all directions. It was proposed to run a sacrificial open hole bridge plug above the loss zone and sidetrack the well instead of performing extensive remedial operations. The proposed solution would help eliminate the well control and HSE risks associated with drilling blindly ahead with the reservoir formation exposed. Applied the proposed solution on the next well that was drilled on the flank of the field, encountered total losses, spotted eight LCM pills, unable to cure the losses, ran sacrificial open hole bridge plug and sidetracked the well. The entire process was completed in 30 hours. Sidetracked the well in adjacent direction to the initial planned well trajectory based on further seismic data analysis and no losses was encountered. Recovered full mud column to surface thus ensuring the restoration of all well barrier elements. This solution has since been adopted as best practice for wells drilled on the flank of the field where there is high probability of encountering total losses. The average time saving per well due to this optimized solution is 450 hours for wells where total losses are encountered. This engineered solution has made drilling wells on the flank of the field in a timely manner possible and at optimized costs. This has resulted in: –The elimination of Non-Productive Time, –Quick delivery of the well to production, –Reduced HSE risk, –Reduced well control risk as loss zone is quickly isolated before drilling ahead. This paper will explain why running sacrificial open hole bridge plugs and sidetracking the well is a more effective solution compared to extended remedial operations when total losses are encountered while drilling across highly fractured / faulted formation. It will discuss the extensive risk assessment conducted, the mitigation and prevention measures that were put in place in order to ensure successful implementation on trial well.
Abstract On a Deep Gas Project in the Middle East, it is required to drill 3500 ft of 8-3/8" deviated section and land the well across highly interbedded and abrasive sandstone formations with compressive strength of 15 - 35 kpsi. While drilling this section, the drill string was constantly stalling and as such could not optimize drilling parameters. Due to the resulting low ROP, it was necessary to optimize the Drill string in order to enhance performance. Performed dynamic BHA modelling which showed current drill string was not optimized for drilling long curved sections. Simulation showed high buckling levels across the 4" drill pipe and not all the weight applied on surface was transmitted to the bit. The drilling torque, flowrate and standpipe pressures were limited by the 4" drill pipe. This impacted the ROP and overall drilling performance. Proposed to replace the 4" drill pipe with 5-1/2" drill pipe. Ran the simulations and the model predicted improved drill string stability, better transmission of weights to the bit and increased ROP. One well was assigned for the implementation. Ran the optimized BHA solution, able to apply the maximum surface weight on bit recommended by the bit manufacturer, while drilling did not observe string stalling or erratic torque. There was also low levels of shocks and vibrations and stick-slip. Doubled the on-bottom ROP while drilling this section with the same bit. Unlike wells drilled with the previous BHA, on this run, observed high BHA stability while drilling, hole was in great shape while POOH to the shoe after drilling the section, there were no tight spots recorded while tripping and this resulted in the elimination of the planned wiper trip. Decision taken to perform open hole logging operation on cable and subsequently run 7-in liner without performing a reaming trip. This BHA has been adopted on the Project and subsequent wells drilled with this single string showed similar performance. This solution has led to average savings of approximately 120 hours per well drilled subsequently on this field. This consist of 80 hours due to improved ROP, 10 hrs due to the elimination of wiper trip and a further 30 hrs from optimized logging operation on cable. In addition, wells are now delivered earlier due to this innovative solution. This paper will show how simple changes in drill string design can lead to huge savings in this current climate where there is a constant push for reduction in well times, well costs and improved well delivery. It will explain the step-by-step process that was followed prior to implementing this innovative solution.