Africa (Sub-Sahara) Sonangol's deepwater Orca-1 well encountered oil in the presalt layer of Block 20/11 in the Cuanza basin offshore Angola. The well reached a measured depth of 12,703 ft. Initial well tests saw flow rates of 16.3 MMcm/D of gas and 3,700 BOPD. Cobalt International Energy (40%) is the operator, with partners Sonangol Research and Production (30%) and BP Exploration Angola (30%). Asia Pacific Premier Oil's Kuda Laut-1 well in Indonesia's Tuna production sharing contract has encountered 183 net ft of oil-bearing reservoir and 327 net ft of gas-bearing reservoir. Following evaluation operations, the well will be sidetracked to drill the Singa Laut prospect in an adjacent fault block. Premier is the operator (65%), with partner Mitsui Oil Exploration Company (35%).
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.
Well tests for smart, horizontal wells in faulted and heterogeneous reservoirs with complex fluids and uncertain contacts are nearly impossible to design and interpret with geological consistency using traditional analytical methods. Such cases lend themselves to numerical reservoir simulation, but the number of uncertain parameters and their interaction can make design difficult and the interpretation process time-consuming. We used an uncertainty-based technique for test design and interpretation with numerical models for a test in the Norwegian Barents Sea. We describe a new global sensitivity analysis methodology to determine how the interaction of multiple uncertain reservoir parameters (such as water contact depth, fault transmissibility, reservoir permeability, and anisotropy) influences the uncertainty in the pressure derivative response. With time-dependent plots of parameter sensitivity, confident decisions can be made about the test duration and the ability to address test objectives.
Our methodology shows how exploration of the full range of reservoir uncertainty gives confidence in the expected flowing conditions, which are used to manage operational risks. The results of the design study, which are fully-integrated with the geological and geophysical description of the reservoir, are used during real-time monitoring and final interpretation. The full methodology was applied for the first time to a well test targeting the shallow Mid-Jurassic Stø Formation in Wisting discovery, the northernmost oil discovery situated in the Hoop area of the Barents Sea. The test design clearly indicated that water breakthrough was not expected but that gas production could not be ruled out given the range of uncertainty of the reservoir parameters.
The test was monitored in real time. From the hundreds of cases produced and analyzed, matches were obtained during monitoring to give an indication of the future behavior of the well during the final buildup. This helped to dictate the test plan and buildup duration.
As predicted, interpretation of the final derivative was challenging due to reservoir complexity. Traditional analytical interpretation could easily have suggested sealing faults in the near-well vicinity. However, using an amalgamated numerical model derived from the initial real-time matches and then further calibrated to the test data, we provided an interpretation of all the data obtained during the test, including matching the liquid ratios and accounting for wellbore dynamics. We not only achieved a good pressure and pressure derivative match with a model coherent with the geology, but also confirmed connected volumes.
AbstractThis paper describes a unique combination of equipment and techniques that enabled an ESP-DST well test on a shallow, horizontal well drilled in a faulted and heterogeneous reservoir with complex fluids, in Arctic conditions.The technical challenges of the performed well test included designing a bespoke ESP-DST string compatible with the shallow reservoir and designing a surface well test spread capable of efficient separation for safe and environmentally friendly disposal, and obtaining accurate flow rate measurements, as well as performing a test with interpretable data given the uncertainty and complexity of the formation, and the complexity of the well itself.The success of the performed well test was the result of an integrated approach to well test design and real-time support provided throughout. This process included the selection of optimum ESP-DST string design for multizone testing in a high angle well including an innovative arrangement of an ESP encapsulated in a POD and installed in the riser. Integration of ESP with the surface well test package was also important and the design of the surface well test package included a Coriolis type of separator and multiphase flow meter for accurate flow rate measurements.During drilling, the contingency plan to mitigate against losses was implemented which had a significant effect on the well testing program. To address this, and to understand if the well objectives could still be achieved, an uncertainty-based well test design and interpretation methodology, taking into account reservoir uncertainties and their interaction with each other, which uses numerical models and a global sensitivity analysis method was applied. This method identifies which uncertain reservoir parameters can be interpreted confidently and indicates the test duration. From the hundreds of numerical simulation cases produced during the design stage of the test, matches were obtained during monitoring to give an indication of the future pressure behavior, which allowed the duration of final build-up to be optimized.The ESP-DST well test was successfully performed on a horizontal well drilled in the Wisting discovery in the Barents Sea. The well was successfully free flow tested giving a maximum achieved flow rate of 5,000 barrels of oil equivalent per day. All the well test objectives were successfully achieved, despite the change to the contingency drilling plan.
The Goliat field development is challenging because of its extreme and remote environment in Barents Sea. The field consists of two separate main reservoirs, Realgrunnen and Kobbe, both having complex structural setting with a high number of faults and considerable reservoir heterogeneity. In order to maximize production, producer wells usually navigate through several sand sequences. In addition, proximity to oil-water-contact (OWC) in the Kobbe formation has to be considered to avoid early water break through.
Eni Goliat team selected deep directional resistivity reservoir mapping LWD technology for geosteering and detecting payzone remotely. Being able to map multiple formation layers away from the wellbore, the service helped G&G team to optimize well paths during drilling to achieve the target sand exposure in the different sequences.
The results presented here on both the Realgrunnen reservoir and Kobbe reservoir were excellent. The producer well C was successfully geosteered in the upper sands in Realgrunnen reservoir, achieving a NTG of 70% despite the presences of subseismic scale faults and lateral facies heterogeneities along the well.
For the producer well E in the Kobbe reservoir, although the well was landed deep and close to OWC because the top reservoir came 11 meter deeper than prognosis, the accurate mapping of the top reservoir, OWC, and optimizing the well path, helped to support the decision to build aggressively and level out at optimal TVD, achieving 340 meters in the Kobbe 9 sand.
This communication will present also how cautious and in-depth evaluation, extensive pre-drilling study and operation planning enabled efficient geosteering of the horizontal producers in this challenging environment and maximizing productivity delivered. Post drilling, the mapping of the reservoir structure and fluid contacts were used as inputs to the static model and integrated into future development plans.