Application of proper technologies in the heavy and extra-heavy oil field of the Orinoco Oil Belt of Venezuela has led to significant improvements in oil production during the last 30 years. However, the many cold production methods tested in the area have achieved a maximum recovery of only 20%. Increasing the recovery factor remains a priority for the oil industry and has led to the testing of hot production methods, such as steam-assisted gravity drainage (SAGD). SAGD uses two parallel horizontal wells, one drilled above the other, with continuous steam injection to achieve recovery efficiencies up to 60% in many heavy and extra-heavy oil fields worldwide. Magnetic ranging technologies are used to maintain precise separation along the trajectory of the two wells, which is critical for the effectiveness of SAGD technique. If the horizontal wells are too close, the steam will rapidly migrate to the production well. If there is excessive separation, gravity drainage will not occur. A national Venezuelan operator determined that SAGD technology is applicable in the San Tome area of the Orinoco heavy-oil Belt and proposed to drill a pair of SAGD wells in the U1, 3 MFB-53 reservoirs to evaluate the effectiveness of the technology to recover an additional 2 MMBB. Increasing the recovery factor to 38% in the area affected by injection with a rate of 1,500 BNPD and holding it for 3 years will determine the success of the technique in the Orinoco Oil Belt. This publication will describe the characteristics and production history of the Bare Reservoir, as well as the implementation of SAGD drilling techniques in the development of related fields. Specifically addressed will be how the precise pre-planning and execution of the separation and alignment between the two existing wells was achieved using active magnetic-ranging technology. Finally, production results will be presented and explained.

This paper has the recommended procedures to be carried out in each phase: Surface, Intermediate I and II, horizontal and completion with frac string, for Unconventional Appraisal HP/HT wells across Deyab formations in Abu Dhabi (UAE), as well as the technology to be used and avoid, to drill the wells saving time and money helping to make a rentable project. Due to the information received of the zone was scarce, in addition the first well in the area (offset well and taken as a reference) had many operational problems. The operations during drilling the next three wells in PAD # 1 were recorded, analyzed and optimized, resulting in a learning catalog for the area, saving a considered quantity of rig days with a huge impact in the budget and the most important, the exposure of the crews/people at the location was minimized to this hazard environment. The PAD# 1 has 03 horizontal wells, the design is Heavy Casing Design, where each phase has its characteristics to be drilled and cased. The reservoir consists of 03 cl early identified formations: Jubaila, Hanifa and Tuwaiq Mountain into the range from ± 12330 ft. TVD to ± 12900 ft. TVD. Reaching the targets with horizontal wells from 16,000 ft. MD to 17,500 ft. MD. After analyzing each section and getting the recommendations from different service companies and specialist, the changes were implemented in the next well regarding drilling fluid MW, BHA's design, bit type & design, wiper trips, slurries, trajectories, etc. taking as result drilling wells more complicate d without operational issues, in deepest formation, drilling more than 1000 ft. MD and 600 ft. TVD, and saving 3.25 MM$ and 15.2 days per well The PAD # 1 in Deyab field, is the pioneer for the initial development of fracking in UAE. There hasn't had a drilling procedure in detail to reach the target without having issues. This new concession has been already of interest to be developed in conjunction with the National Company, so create a Drilling Learning Catalogue as add value at the moment to handover the wells is a must.

Producing oilfields are an excellent target for production re-development plan and optimization projects. All the wells were drilled and producing/injecting, fluid samples and ratios are known, artificial lift methods are usually in place, networks were installed, facilities were dimensioned and historical data is available.This detailed information can be used to feed and calibrate advanced reservoir and network models which can be coupled in an integrate asset modeling platform. Coupling reservoir simulation models with surface networks permits each discipline, reservoir and production, to focus on detailed representation of field information gathered and allows the constrains of each part of the system to be imposed simultaneously.Therefore, integrated asset modeling generates representative field production forecast and the opportunity to quantify many improvement scenarios options. These options are not limited but include modify gas-lift allocations, surface back-pressures and increase facilities capabilities.This paper describes the methodology applied to the development of an integrated asset modeling study for a brown offshore oilfield in Brazil and the technical challenges faced. The project conducted included six reservoir models coupled to oil production, water injection and gas-lift distribution networks in order to evaluate the current production and future optimization scenarios.The results obtained with this project demonstrated the impact of current water treatment facility in the field oil recovery and the potential gains associated with gas-lift optimization. ReservoirThis Integrated Asset Model study was performed on a field that contains some reservoir compartments, each of them modelled with one independent reservoir model using ECLIPSE. The field layout consists of one single production platform with production fluid limit of 180,000bbl/d and water treatment maximum capacity of 100,000bbl/d. Producing Network ModelThis Integrated Asset Model project includes wells, production network and facilities, gas-lift delivery network and water injection system. The entire network was developed using PIPESIM software for well and network modeling. All producing wells are satellite with a dedicated flowline and riser to connect each well to the production platform.This project was developed using stages approach so that the huge amount of data and modeling work involved could be managed efficiently and smoothly. The major stages were:

To meet the current oil and gas market challenges, there is an industry need to optimize cost by safely drilling longer horizontal wells to maximize well productivity. Drilling challenges include the highly deviated trajectory that starts from the surface sections and wellhead, the high DogLeg Sevirity (DLS) profile with collision risks, and the thin complex geological structures, especially in new unconventional fields where numerous geological and geomechanical uncertainties are present. To mitigate for those challenges, reviewing the existing drilling techniques and technologies is necessary. To compete in the current Hi-Tech and Automation era, the main challenges for directional drilling service providers are to reduce well time, place wells accurately, and improve reliability, reducing repair and maintenance costs and helping the customer reduce time and costs for the overall project. Offset wells analysis and risk assessments allowed identifying the main challenges and problems during directional drilling phases, which were highlighted and summarized. As a proposed solution, the new generation of intelligent fully rotating high dogleg push-the-bit rotary steerable system has been implemented in the UAE onshore oil and gas fields to improve the directional drilling control and the performance. This implementation reduced the Non-Productive time (NPT) related to the human errors as the fully automation capabilities were being utilized. The new rotary steerable system has the highest mechanical specs in the market including self-diagnosis and self-prognosis through digital electronics and sophisticated algorithms that monitor equipment health in real-time and allow for managing the tool remotely. As a result, the new intelligent RSS was implemented in all possible complex wellbore conditions, such as wells with high DLS profile, drilling vertical, curve, and lateral sections in a single trip with high mud weight and high solid contents. Automation cruise control gave the opportunity to eliminate any well profile issues and maintain the aggressive drilling parameters. Using the Precise Near-bit Inclination and Azimuth and the At-Bit Gamma real-time data and high-frequency tool face measurements in the landing intervals where required for precise positional control to enable entering the reservoir in the correct location and with the correct attitude helping the customer's Geology and Geophysics department to place wells accurately while maintaining a high on bottom ROP.