One of the goals cherished by modern organizations is gender balance, as a proven way to enhance productivity, boost the motivation of employees and enrich the leadership pipelines of internal succession plans. The energy sector follows closely this trend, inclusive of major organizations of operations and services, especially in Oil and Gas. And in no other region of the world this is now more visible than in the Middle East, one of the most active and traditionally leading and strategic regions in the segment. This paper summarizes what factors were fundamental for the very visible blooming of the female leadership, particularly in the oil and gas sectorin the Gulf Cooperation Council GCC countries. Certainly, middle-eastern women do not account yet for a large or representative number inthe highest roles of private or National Oil Companiesof their countries, but things are rapidly changing, and the blooming is real.
A comparison of key elements considered diagnostic about the empowerment of women, like female workforce percentages, gender gap indexes, and representation of women in leadership roles in oil and gas are herein analyzed for the GCC, comparing those with figures of other regions of the World. Other indicators were included in the analysis, which proved to be key for developing women's leadership, in particular, communication strategies, empowering plans, training, active and visible endorsement of top leaders and other strategies of governmental agencies and corporations. Definitively, the Middle East, and particularly the GCC countries, in which our study is centered, have boldly address cultural issues and traditional barriers, to produce step-changes that are quickly transforming the oil and organizations in all countries of the region. A forecast of opportunities for women's leadership in the upstream and downstream sectors of the oil industry in the future is proposed, in a story of learned best practices worth sharing.
The paper includes a summary of the standing and utilization of social media channels by main organizations in oil and gas. A frame of the current trends analyzed resulted in the identification of the organizations more successful in the utilization of these key channels, so relevant for the general audiences and the new generations. Some unexpected findingsshaped our conclusions about strategies instrumental for step-changes needed in political or cultural settings that may be challenging for boosting women's empowerment.
Green fields today mostly can be regarded as marginal fields and successfully developed. It covers the complete assessment of the oil and gas recovery potential from reservoir structure and formation evaluation, oil and gas reserve mapping, their uncertainties and risks management, feasible reservoir fluid depletion approaches, and to the construction of integrated production systems for cost effective development of the green fields. Depth conversion of time interpretations is a basic skill set for interpreters. There is no single methodology that is optimal for all cases. Next, appropriate depth methods will be presented. Depth imaging should be considered an integral component of interpretation. If the results derived from depth imaging are intended to mitigate risk, the interpreter must actively guide the process.
Moving their directional drillers into their Houston real-time remote operations centers has improved drilling efficiency for two of the top shale producers. This paper presents a factory-model approach to improving CT drillout performance that has been used successfully for more than 3 years and has become standard practice. The oil industry is currently undergoing a technological transformation that will add value, improve processes, and reduce cost. Future drilling engineers will have knowledge of robotics, automation, and organizational efficiency, which is highly appealing for recruitment. This paper describes challenges faced in a company’s first deepwater asset in Malaysia and the methods used to overcome these issues in the planning stage.
The Burgan field is an oil field situated in the desert of southeastern Kuwait. Burgan field can also refer to the Greater Burgan--a group of three closely spaced fields, which includes Burgan field itself as well as the much smaller Magwa and Ahmadi fields. Greater Burgan is the world's largest sandstone oil field, and the second largest overall, after Ghawar. The Greater Burgan field includes two smaller fields the Magwa and the Ahmadi. Chief Executive of the Kuwait Oil Company reported that Burgan produced half of Kuwait's oil.
This paper presents the traditional methods of hydrate mitigation used in the NKJ fields and the way in which a transient model was initially built and continuously improved. In thermal enhanced oil recovery there is one big ingredient: steam. A new startup from Germany believes it has found the oil industry’s cheapest way to make it. This study provides technical analysis of the viability of enhanced-oil-recovery (EOR) processes; the results indicate the potential for significant improvement in recovery efficiency over continued waterflooding. The first multilateral well in a North Kuwait field has been drilled recently.
Burgan Marrat, a deep carbonate reservoir was transferred from exploration to development team for an accelerated production of the newly discovered oil. This multi-billion barrel reservoir is spread over 450 km2, has more than 40 faults, 8 compartments with large variation in oil-water contact and reservoir/fluid characteristics. The objective of this work is to understand the key uncertainties and quantify their impact on the reservoir offtake rate and oil recovery by conducting uncertainty assessment.
An interdisciplinary team identified the key uncertainty parameters expected to have significant impact on the reservoir development. The range and probability distribution law for each parameter was set considering the uncertainties due to limited measurements or variation in interpretations. A Response Surface Model (RSM) was created to evaluate the uncertainties by using a base dynamic model and applying an appropriate experimental design, which allowed to efficiently study the uncertainty space with a feasible number of simulations. Using the RSM, the primary effects and interaction between parameters were quantified to rank the uncertainties based on their impact on field production.
Key uncertainty parameters were identified including eight OWCs, six fault transmissibilities, horizontal and vertical permeability multipliers, and porosity multiplier. Latin Hypercube was found to be the appropriate Experimental Design for the study considering 17 parameters and the need of building a reliable RSM that includes interactions between them. The design recommended 155 simulation cases, which were prepared and submitted automatically by the software.
Multi-time Responses were analyzed qualitatively to identify the top 5 uncertainties having material impact on field production over 20 years considering 6 existing wells and 30 new well locations. The RSM quantitative evaluation showed three parameters (OWC2, OWC4 and OWC1) having a total effect on the response higher than 10%; followed by PERMX and OWC3 with less than 5%. The other 12 parameters have total effects less than 2%, and the interactions effect is less than 0.5% for any interaction between two parameters. Contrary to the intuition, none of the faults proved impact on the reservoir production.
The results prove very useful to make a right development and appraisal strategy in early life of the reservoir. The new well locations can be ranked and prioritized to optimize the development and effectively appraise the areas with high risks.
Uncertainty assessment has value throughout the life of the reservoir. However, this study indicates that its application in early life of the reservoir can bring immense value. An uncertainty analysis on the reservoir production helps in decision-making regarding the number of wells and their locations to reach a target production by managing the risks.
Al-shammari, Baraa Sayyar (Kuwait Oil Company) | Rane, Nitin (Kuwait Oil Company) | Ali, Shareefa Mulla (Kuwait Oil Company) | Sultan, Aala Ahmad (Kuwait Oil Company) | Al Sabea, Salem Hamad (Kuwait Oil Company) | Al-naqi, Meqdad (Kuwait Oil Company) | Pandey, Mukul (Weatherford) | Solaeche, Fernando Ledesma (Weatherford)
The Kuwait Integrated Digital Field project for Gathering-Center 01 (KwIDF GC-01) at Burgan Field acquires real-time data from wells and processing facilities as input for its production-surveillance program. Live data from the field is fed into an integrated production model for analyzing and optimizing pump performance. An automated workflow process generates alarms for critical well and facility parameters to identify wells with potential scaling issues. KwIDF workflows are integrated with updated well models to visualize the effect of scale build up on the wellhead performance and thereby assist in quantifying the associated production losses caused by scale deposition. A sensitivity analysis is also performed to identify current and optimal pump operating conditions and prioritize scale cleaning jobs.
The exception-based surveillance of key real-time parameters for wells utilizing electrical submersible pumps (ESPs) in Burgan field has significantly improved diagnostics of scale deposition at wellhead chokes and flowlines. Automated workflows calibrate an integrated production model in real-time, which enables engineers to run a quick analysis of current pump operating conditions and make a proactive plan of action. The application of real-time data and automated models has aided the operator's production team in making informed and timely decisions that enable them to run pumps at optimal operating conditions, with the result that they are able to sustain well production at target levels.
This paper describes an innovative approach to applying real-time data and integrated models in an automated workflow process for enhancing capabilities to diagnose scale deposition in the surface flow network. Examples are presented to demonstrate the application of integrated technology for identifying scaling at wellhead chokes and flowlines and prioritizing a scale removal program for optimizing pump performance.
The case study describes a modeling and simulation study of an inverted ESP completion to address three fundamental objectives. A) Increasing the ultimate oil recovery in the massive sands of Cretaceous age in Greater Burgan field by managing water production B) Mitigating the rapid water coning conditions in this high permeable water drive reservoir and C) Designing an optimal operating strategy with Downhole Water Sink (DWS) to control water production and manage well performance. A 2×2km sector was carved out from the full field geological model with 12 wells including the study well. The study well was producing at high water cut at the time of the study. All static properties were updated, and the model was history matched for production, pressure and saturation. Several sensitivity runs were performed, and prediction scenarios were run for 5 years to observe well production behavior in time. The well model was setup with an inverted ESP between straddle packers to produce water from below OWC and inject into bottom reservoir with a production string above to produce from the oil zone. This setting ensured a reverse oil cone being generated from below OWC in the reservoir under production. The aquifer model was finite in size enabling bottom water influx. Simulation results showed that implementation of DWS technology made the water production reduced by 18% during five years with an increase in oil production of nearly 25% in the study well. To maintain continuous well offtake rate, a range of water rates to be produced and injected to bottom reservoir have been studied. Several iterative runs were made to investigate the best completion interval and injection & production rates. The profiles of oil water interface near well bore indicated good reduction in the cone height as compared to normal completion. The results also showed significant improvement in oil recovery within the drainage radius of the well from the simulations. Simulation results provided good understanding of the saturation change near well bore area under different production rates. Prediction runs were made for sustainable oil production under natural flowing condition and the conditions to switch over to production under artificial lift. Production of thin layers of remaining oil from within high permeable massive Burgan middle sands has been a high concern due to very high water cuts because of coning. The study results have provided encouraging option with DWS technique to improve recovery from the reservoir.