Permeability values of rocks range over many factors of 10; therefore, permeability is plotted on a logarithmic scale. Values commonly encountered in petroleum reservoirs range from a fraction of a millidarcy to several darcies. This page discusses factors affecting permeability associated with different rock types. The log10(k)-Φ plot of Fig.1 shows four data sets from sands and sandstones, illustrating the reduction in permeability and porosity that occurs as pore dimensions are reduced with compaction and alteration of minerals (diagenesis). Porosity is reduced from a maximum of 52% in newly deposited sandstones to as low as 1% in consolidated sandstones.
Two upscaling exercises performed in 2013-14 and 2017-18 on two onshore green fields with conventional to viscous oil are presented, for which the upscaling tried to compensate the effects of grid coarsening, in particular the increase of numerical dispersion and the decrease of heterogeneity. Our methodology was to adjust the water/oil relative permeabilities called pseudo KRs in the coarse scale simulation, in order to reproduce the behavior in terms of pressure, rates, saturations and concentrations of the fine scale model, which was using microscopic rock KRs based on laboratory data.
As the upscaling depends on the fluid injected, it was done separately for waterflood and polymer flood. When done with polymer flood, the concentration of polymer had to be history matched also mainly by adjusting the Todd-Longstaff mixing parameter in addition to the KRs. As upscaling is case dependent, it was performed on several geological models, varying heterogeneity and grid size, but also rock KRs and even precocity of the polymer flood after some waterflood, to test the robustness of the approach.
It was found that pseudo-KRs for waterflood could be slightly degraded for viscous oils, whereas the upscaling was more neutral for conventional oils. This correlates well with field observation for viscous oils, where water production occurs generally a bit quicker than what numerical simulation predicts when using rock KRs, in absence of upscaling.
For polymer floods, which were considered in secondary or early tertiary mode, pseudo KRs were generally improved, mainly because the polymer steepened the saturation fronts, which can be well represented only with small lateral grid size.
The result of both upscaling exercises was that the increment of polymer flood versus waterflood was noticeably higher when computed on high resolution modelling. This is equivalent to saying that when using pseudo KRs resulting from this high resolution matching, the polymer increment on coarse grid is significantly higher than if computed without pseudo KRs. This improves the economic evaluation of the project, increasing the willingness to de-risk and implement early polymer floods on these fields.
Alkhazmi, Bashir (Centre for Enhanced Oil Recovery and CO2 Solutions, Heriot-Watt University) | Farzaneh, Seyed Amir (Centre for Enhanced Oil Recovery and CO2 Solutions, Heriot-Watt University) | Sohrabi, Mehran (Centre for Enhanced Oil Recovery and CO2 Solutions, Heriot-Watt University)
A Water-alternating-gas (WAG) injection is a broadly practised technique in oil fields. Gas viscosity is a significant parameter that can affect the efficiency of gas and WAG injections. By conducting the current coreflood experiments at reservoir conditions, we aimed to investigate the effect of gas viscosity on gas and WAG injection performance in terms of oil recovery and differential pressure.
Both WAG injection experiments were performed on the same Clashach sandstone core, under weakly water-wet and near miscible (gas/oil IFT = 0.04 mN.m-1) conditions, using two different hydrocarbon systems (C1-nC4 and C1-nC10). To eliminate the impact of the experimental artifact, a long and large core (2ft x 2 in) was employed. In addition, after each initial water injection, water was pumped through the core at multi-rates, for further investigation of the impact of capillary end effects on our experimental results. To facilitate the interpretation of the data and the comparison, the same injection strategy and methodology were followed in both coreflood experiments. In each injection scenario, four water slugs, starting with primary water flooding, were injected in an alternating manner with four gas cycles.
The results of these WAG experiments showed that the cyclic oil recovery performance during different water and gas injection cycles increased as the number of WAG slugs increased. Investigating the effect of gas viscosity on the performance of oil recovery during gas and WAG injections revealed higher oil recovery performance during the tertiary (three-phase displacement) water injection cycles that were subsequent to the preliminary water flood periods, in WAG injection with C1-nC4 than that in C1-nC10. In contrast, the efficiency of oil recovery during the successive gas injection cycles (under three-phase conditions) was lower in C1-nC4 than that in C1-nC10. The ultimate oil recovery achieved by WAG injection under weakly water-wet and near miscible conditions reached 93 % and 94.5 % (IOIP %) in C1-nC4 and C1-nC10 respectively. On the other hand, the results showed also an extra oil quantity of 3.7 % (Sor%) recovered during the alternation of water and gas injections post-waterflood, by C1-nC10 compared with that in C1-nC4. Studying the impact of the gas viscosity on the injectivity showed a significant drop in the periodic gas injectivity, during different gas injection cycles in WAG injection for C1-nC10 compared with its values for C1-nC4.
A comprehensive series of data sets, generated for two WAG injection experiments with different hydrocarbon fluids (C1-nC4 and C1-nC10) will be reported in this paper. WAG injection is a special case that involves complex multi-phase and multi-physics processes, which are well-known to be difficult to reliably predict by the current existing reservoir simulators. Therefore, representative and reliable experimental data are needed to improve our understanding of the complex underlying mechanisms of oil recovery by WAG injection and to develop improved models and methodologies for reliable predictions of the performance of WAG injection under reservoir conditions.
This paper provides perspective on the current state of multizone completion technology and issues encountered in the industry with developing a system that offers increased capabilities to meet the increasing challenges presented by the Lower Tertiary in the Gulf of Mexico. The lower tertiary formation found in the pre-salt layers of the Gulf of Mexico has become a proving ground for extending what is possible when completing multistage fracturing in ultradeepwater wells.
Africa (Sub-Sahara) Algeria awarded four of 31 oil and gas field blocks on offer to foreign consortiums in its first auction since 2011. Shell and Repsol won permits for the Boughezoul area in the north of the country, while Shell and Statoil won permits for the Timissit area in the east. A consortium of Enel and Dragon Oil was awarded permits for both the Tinrhert and the Msari Akabli areas. Circle Oil's CGD-12 well, located onshore Morocco in the Sebou permit, encountered natural gas at different levels within the Guebbas and Hoot sands. Wireline logging analysis confirmed a net 9.7 m of pay. The first test, over the Intra Hoot sands, flowed gas at a sustained rate of 2.21 MMscf/D through an 18/64‑in. The primary target, the Main Hoot sands, flowed at a sustained rate of 4.62 MMscf/D through a 24/64-in.
Africa (Sub-Sahara) Vaalco Energy started oil production from the Etame 12-H development well offshore Gabon. The well was drilled to a measured depth of approximately 3450 m and was targeting the recently discovered lower lobe of the Gamba reservoir. It was brought on line at a rate of 2,000 BOPD with no indication of hydrogen sulfide. Vaalco (28.07%) is the operator with partners Addax Petroleum (31.63%), Sasol (27.75%), Asia Pacific KrisEnergy started drilling the Rossukon-2 exploration well on Block G6/48 in the Gulf of Thailand, using the Key Gibraltar jackup rig. The well will reach a total depth at 5,462 ft and will test Early Miocene stacked fluvial sandstones on a broad structural high.
Eni started production from the Perla giant gas field located in the Gulf of Venezuela, 50 km offshore. Consisting of Mio-Oligocene carbonates with excellent characteristics, the reservoir is approximately 3000 m below sea level and lies at a water depth of 60 m. The best wells are estimated to produce more than 150 MMscf/D of gas each. The development plan includes 21 producing wells and four light offshore platforms linked by a 30-in. Two treatment trains have been installed at the facility, each capable of handling 150 Mscf/D and 300 Mscf/D of natural gas.
Africa (Sub-Sahara) Bowleven's Moambe exploration well on the Bomono Permit onshore Cameroon has encountered hydrocarbons. The well was drilled to a planned total depth of 5,803 ft and made its discovery in Paleocene-aged (Tertiary) target reservoir intervals. Moambe is the second in a two-well exploration program on the permit. The first well, Zingana, also discovered hydrocarbons. The Moambe well will be tested before further testing takes place at Zingana. Bowleven holds 100% interest in the permit. Shell Nigeria Exploration and Production has begun production at the Bonga Phase 3 project, an expansion of the deepwater Bonga project in Nigeria. Peak production from the expansion is expected to be 50,000 BOEPD, which will be shipped by pipelines to the Bonga floating production, storage, and offloading facility.
Baruah, Nabajit (Oil & Natural Gas Corporation) | Mandal, Dipak (Oil & Natural Gas Corporation) | Jena, Smita Swarupa (Oil & Natural Gas Corporation) | Sahu, Sunil Kumar (Oil & Natural Gas Corporation)
This paper examines the prospect of Gas Assisted Gravity Drainage (GAGD) process in improving recovery from a sandstone reservoir by injecting produced gas back into the crestal part of the reservoir. Besides recovery improvement, immiscible gas injection ensures near Zero Flaring strategy. The process has been found to be ideal in reservoirs with high permeability and reasonable dip to maximize oil production wherever a sufficient gas source exists. Based on the study, gas injection is recommended at the crestal part of the reservoir under study at the rate equivalent to the produced gas to maintain pressure, arrest gas cap shrinkage and improve recovery.