Africa (Sub-Sahara) A drillstem test was performed on the Zafarani-2 well--located about 80 km offshore southern Tanzania. Two separate intervals were tested, and the well flowed at a maximum of 66 MMscf/D of gas. Statoil (65%) is the operator, on behalf of Tanzania Petroleum Development Corporation, with partner ExxonMobil Exploration and Production Tanzania (35%). The FA-1 well--located in 600 m of water in the Foum Assaka license area offshore Morocco--was spudded. The well targets Eagle prospect Lower Cretaceous resources. Target depth is 4000 m. Kosmos Energy (29.9%) is the operator, with partners BP (26.4%),
Africa (Sub-Sahara) ExxonMobil subsidiary Esso Exploration Angola has started oil production at the Kizomba Satellites Phase 2 project offshore Angola. The project involves the development of subsea infrastructure for the Kakocha, Bavuca, and Mondo South fields. Mondo South is the first field to begin production, and the other two satellite fields will follow later this year. The goal is to increase Block 15's production to 350,000 BOPD. Esso (40%) is the operator with BP Exploration Angola (26.67%), Kosmos Energy discovered gas at the Tortue West prospect in Block C-8 offshore Mauritania.
The Cliff Head is one of the most significant discoveries in the offshore Northern Perth Basin. Hence, understanding the structure and geology of the field is essential to further evaluate the offshore region in the basin. Two structural models were developed with the objective to achieve a better understanding of this field. The first model is focused on the Permian and older strata, while the second model is for the overburden. In addition, reservoir properties models (e.g. porosity model and water saturation model) were developed to better understand the reservoir facies and hydrocarbon distribution. Examination of the structural models has shown that there are two main sets of faults within the Cliff Head area, which can be categorized into the following: the deep Permian faults that are truncated against the Late Permian unconformity, and younger Cretaceous faults that were developed during the Early Cretaceous rifting. It has also shown that the oil accumulation within the field is structurally trapped within Permian aged set of horsts and is mainly reservoired within the Irwin River Coal Measures. The secondary target (e.g. the underlying High Cliff Sandstone) is mostly beneath the regional oil-water contact of −1257.8 m TVDss, except in the highest structural point in the field, where Cliff Head-6 was drilled. The Irwin River Coal Measures in the study area contained four high resolution depositional sequences that displayed a finingupward pattern as depicted by the Gamma Ray log response and are interpreted to have mainly deposited in a fluvial depositional system. The High Cliff Sandstone, in contrast, contained two high resolution depositional sequences that displayed a coarsening upward sequences as supported by Gamma Ray log response and were interpreted to have mainly deposited in marginal marine settings. Reservoir properties modeling was also conducted utilizing the 3D models, where a 3D porosity model was calculated and shows that the Irwin River Coal Measures, in general, exhibit higher porosity distribution than the underlying High Cliff Sandstone, even though the later has coarser and more laterally extensive sand sheets. This is probably attributed to diagenetic porosity reduction within the High Cliff Sandstone caused by the formation waters. The calculated 3D water saturation model also confirms the presence of a single regional oil-water contact within the field and hence, reservoir heterogeneities and fault seal capacities did not affect the hydrocarbon distribution within the field. Finally, all the calculated models (e.g. lithofacies model, porosity model, and water saturation model) were integrated to estimate the recoverable hydrocarbons in place, where the Cliff Head is estimated to contain a total of 15.2 million barrels.
Advanced levels of depletion cause unexpected reduced pore pressures and thus reduced reservoir fracture gradients, presenting considerable drilling challenges in the Burgan Field in Kuwait. This can lead to matrix damage due to mud losses and result in borehole collapse due to the relative increase of effective stress concentration in the vicinity of the borehole. The area of the study showed high levels of non-productive time (NPT) as well as increased costs due to the drilling of unplanned sidetracks in highly deviated wells. LWD Penta-combo measurements including azimuthal sonic and formation pressure have been utilized to model fracture gradient and borehole collapse gradient in real-time, and proved effective at reducing risks and rig time by allowing proactive management of these challenges.
Borehole collapse in offset wells was analyzed to predict and simulate the wellbore stability of a planned well via a pre-drill geomechanics model prior to drilling the well. The well was planned with a high deviation of 56° and oil based mud. The salinity of the water phase was recognized as an essential factor in assessing wellbore stability risk with respect to shale-dependent time failure.
The integration of real-time LWD sonic and density data with formation pressure testing data in the geomechanics model for the first time in the 12 ¼-in. section showed excellent correlation and confirmed different levels of depletion in the reservoir. Uncertainty in the modeled fracture gradient was significantly reduced and effectively eliminated with the inclusion of real-time formation pore pressure testing data. This successful combination of modeled pore-pressure curves from the real-time LWD sonic data with the real-time formation pressure test data acquired while drilling in the same run is a first in Kuwait. A total of 15 pressure points were sampled in real time while drilling, allowing for proactive mud window optimization and borehole stability geomechanical analysis.
This real-time wellbore stability technique based on advanced LWD azimuthal acoustic technology in conjunction with real-time formation pressure testing while drilling has been developed with a unique process and workflow allowing the operator to drill the well with no significant wellbore stability issues and with the optimized shape of the borehole for a safe casing run. In addition, NPT was reduced to 0 hours and overall days per well were reduced significantly.
Unconventional gas exploration in the Cooper Basin, Australia, has historically concentrated on fracture stimulation of tight gas sandstones within mapped structural closures. In drilling these sandstones, and other clastic reservoir targets, it has been recognised for many years that the Permian coal measures of the Toolachee, Epsilon and Patchawarra Formations record high levels of gas, often in excess of 4000 units, encountered at depths between 2500 and 3500m. Unlike shallower Coal-Seam-Gas reservoirs, which rely on de-pressuristion through de-watering to liberate adsorbed gas from the kerogen surface, deep coals are a "dry" system in which the free gas component is produced via kerogen and fracture permeability.
However maintaining a consistent and commercial flow rate from deep coals alone remained enigmatic until the first dedicated fracture stimulation program of deep Permian coals was commenced in the Moomba Field in 2007. Understandings of Permian source-rock reservoirs, the roles of the coal type and rank on sorption capacity and porosity, the influence of effective pressure and depth on coal permeability and the interrelation of coal fracture permeability with in-situ stress and mechanical stratigraphy has now advanced.
The deep Permian coal fairway in the Patchawarra and Nappamerri Trough of the Cooper Basin has been defined and mapped using a generative potential approach within a comprehensive 3D basin model. Net coal thicknesses from log electro-facies for 879 wells has been combined with available well maturity, TOC, HI and kerogen kinetic data, and calibrated against corrected temperatures in a basin-wide Trinity retention model which incorporates 14 mapped regional horizons. Play fairways have been overlain with observations of in-situ stress direction and fracture orientations from 3D seismic curvature volumes, FMI data and stress states from Mechanical Earth Models (MEM).
Within the basin, this approach has defined a P50 in-place resource of 14.6 TCF of gas and a P10 of 20.7 TCF of gas within the deep coals of the Permian Toolachee, Epsilon and Patchawarra Formations in Senex permits, of which 8-11 TCF is within the North Patchawarra Trough. MEM's have also demonstrated that deep coal seams are consistently in a normal stress state and therefore provide excellent scope for both propagating and constraining vertical fracture growth. Work is now underway to define further those areas, within the mapped resource parameters, which provide the best opportunity to site pilot lateral wells for multi-stage fracture stimulation within deep coals.
Yanhua, Yao (Baker Hughes, a GE Company) | Ning, Zhang (Baker Hughes, a GE Company) | Qirong, Li (Changning Shale Gas Company, PetroChina) | Yang, Yang (Changning Shale Gas Company, PetroChina) | Jian, Zheng (Changning Shale Gas Company, PetroChina) | Man, Chen (Changning Shale Gas Company, PetroChina) | Li, Yang (Changning Shale Gas Company, PetroChina) | Hao, Zhou (Changning Shale Gas Company, PetroChina) | Zhou, Zhang (Changning Shale Gas Company, PetroChina)
Production in shale is higher related to the well placement in both sweetspot and fracable zone. Due both to market conditions and also shale property, geosteering in tight shale reservoirs have generally employed basic and economical steering tools, such as gamma ray; however, though the tool provides some data to steer the well, the data provided does not allow for predictions of fracability and production potential of the shale rock. This paper introduces a new geosteering approach, which augments existing techniques by providing data to also help well placement, then design stage and perforation location. This novel formation evaluation technique is essentially building a quantitative model of "sweetspot fracable window" for shale, which can help to land and target most prospective zones. The main quantitative data is obtained through measurement of cuttings samples at well-site in semi-realtime on a field portable SEM (
Case studies have shown that maintaining the well path in the sweetspot fracable window can result in better well production after fracturing. And thus, the goal for geosteering is to ensure as much as possible that the horizontal well trajectory is maintained within this window. Additionally, the cuttings data generated during the drilling process can also be used both during and after TD to generate optimized completion design, aiming to further maximize well productivity. The case study also shows that, compared with conventional wireline logging data, the on-location cutting based analysis is able to generate richer mineralogical and elemental data throughout lateral wells, providing a better understanding of geological heterogeneity. Meanwhile, the author also applies several strategies to calibrate the cutting depths and cuttings’ time lags.
This approach can provide a fast analysis for enhanced reservoir navigation, to keep the well trajectory within a predefined sweetspot fracable zone. The production analysis of the wells, hereafter, verifies the higher rate of intersecting into sweetspot fracable zone, the higher production the well receives. This then assist in generating cost-effective completion optimization of stage placement and perforation, with the ultimate goal of increasing the investment returns.
In conclusion, the production statistics of the wells verifies the higher rate of intersecting into sweetspot fracable zone, the higher production the well receives. The goal for geosteering is to ensure as much as possible that the horizontal well trajectory is maintained within this window.
Fialips, Claire I. (Total S.A.) | Labeyrie, Bernard (Total S.A.) | Burg, Valerie (Total S.A.) | Maziere, Valerie (Total S.A.) | Muneral, Yann (Total S.A.) | Haurie, Helene (Total S.A.) | Jolivet, Isabelle (Total S.A.) | Lasnel, Regis (Total S.A.) | Laurent, Jean-Paul (Total S.A.) | Lambert, Laurent (Total S.A.) | Jacquelin-Vallee, Laurence (Total S.A.)
Most of the Nuclear Magnetic Resonance (NMR) log based permeability models require the estimation of the irreducible water saturation (Swirr). Several methods are available for calculating this parameter using NMR relaxometry. The most straightforward method with the lowest accuracy is to consider a fixed relaxation time (T2) value. It has been suggested to use a T2-cutoff equal to 10 ms for tight reservoirs. Another traditional experimental method involves centrifuging core plugs to Swirr. In this paper, an additional approach to separate free and bound water using NMR relaxation time is introduced. This method involves the area under the amplitude-T2 relaxation time graph.
A series of experiments were conducted on 81 core plugs. These samples are mainly from the Western Canadian Sedimentary Basin. Core plugs are from Montney, Nordegg, Mist Mountain, Red Beds, Doig, Killam, Lathom, York River, Wapiti, Teslimkoy, Kesan, and Ordivician Quartz formations. NMR measurements were obtained initially on the dry cores to establish the presence of any liquids that were not cleaned or any isolated porosity. The air permeability was measured using an in-house permeameter. The cores were then brine saturated in two steps of spontaneous imbibition followed by forced imbibition under vacuum. The Archimedes principle was used to measure the sample pore volumes. Porosity was subsequently calculated. NMR relaxation data were then acquired on the brine-saturated cores. Then the core plugs were centrifuged under air to an expected irreducible saturation. NMR relaxation times were obtained on all cores at Swirr.
NMR porosity, T2gm, Irreducible Bulk Volume (BVI), and Free Fluid Index (FFI) were calculated. Swirr was calculated with the three aforementioned methods. Excel Visual Basic for Applications (VBA) programming language was employed for analyzing the relaxation times. The Timur-Coates model was applied for permeability calculation using all the aforementioned Swirr estimation methods. Data were analyzed, and discrepancy analysis was conducted.
The implemented area analysis method has been used previously in reservoir typing based on formation types and also as a factor in one permeability model. However, this is the first time this approach is used in calculating FFI/BVI exclusively. This method is faster than conventional estimators, and it is the only method that can implement Timur-Coates based permeability models for logging tools. From the experimental point of view, only a single NMR measurement is needed. Centrifuging the cores is not necessary. The possibility of cracking these cores due to spinning is eliminated. This new approach is less computationally demanding, and calculations are easier to perform. It is proven that the fast peak area method is more accurate than the fixed T2-cuttoff and in some cases the centrifuge method.
This study investigates the seismic response of organic-rich shale in-situ conditions. The aim is to understand the interrelationship between rock properties and elastic properties, as well as the main factors that affect the elastic properties of organic shale. The use of rock physics relationships is important in understanding the seismic responses of shale gas formations when constrained by geology and formation-evaluation analysis. Seismic inversion can be used to identify organic-rich shales from lean shales and help further our understanding of their properties. Different approaches of seismic inversion and multi-attribute analysis were conducted by combining three dimensional (3D) seismic data with log data to determine hydrocarbon sweet spots within shale formations in the north of the Perth Basin. This study shows that the Acoustic Impedance (AI), which is the product of compressional velocity and density, decreases linearly with increasing Total Organic Carbon (TOC) content in shale gas formations. TOC was obtained using Roc-Eval pyrolysis for more than 120 shale core samples from the Perth Basin. By cross-plotting the AI derived from seismic data against the measured TOC content, it became possible to map TOC variations directly from 3D seismic data. Our investigations have found that the hydrocarbon sweet spots are characterized by high TOC and relatively high AI, which is found in the base of Hovea Formation (hot shale), with a TOC of around 4%.
Post-stack inversion and attributes are used to map discontinuities and structural trends that may influence the drilling or production, though unconventional natural gas reservoirs are challenging to characterise due to the elastic properties of shale rock varying significantly within and across such reservoirs due to variable mineral compositions and fabric anisotropy exhibited by these organic rich shales (Altowairqi et al., 2015; Altowairqi et al., 2013; Zhu et al., 2011).
Evaluation of thermal maturation indicators in thermogenic shale gas reservoirs is critical for the potential assessment and development of unconventional resources. Vitrinite reflectance (Ro) is a commonly used method to quantify the maturation level of organic matter in sedimentary rocks and is widely considered to be a reliable thermal maturity indicator. Although vitrinite reflectance is a well established method, it has been difficult to obtain converging results of Ro during inter-laboratory studies and published research has shown that the reproducibility can be an issue. Alternative thermal maturation indicators are needed for marine shales, where vitrinite particles are absent such as in pre-Silurian rocks, and for sedimentary rocks with low organic contents. The use of Fourier transform infrared spectroscopy (FTIR) and Raman spectroscopy to assess the dispersed organic matter (DOM) in sedimentary rocks and understand its thermal maturity has been previously established. However, very few studies have evaluated the suitability of these techniques for characterising the nature and occurrence of organic matter in shales. The Canning and Perth Basins in Western Australia have been identified as locations that are likely to hold commercial shale gas accumulations, and samples from these two basins have been selected for this study. In this study, a combined FTIR and Raman spectroscopy approach was used for determining the thermal maturity and organic geochemistry of shale rocks with an aim to develop a reliable method to unravel the geochemical characteristics of DOM in such materials. We report the characteristic spectral features of different types of organic matter (macerals) and discuss their correlation with conventional petrographic and geochemical data.
The extraction and production of gas from shales has become an attractive energy source over the last decade. Although shale gas is an established resource in the United States, there is a need to determine its feasibility in Australia’s geological and environmental settings. It has been estimated that Australia could have around 437 trillion cubic feet of technically recoverable shale gas (EIA, 2013). The Canning and northern Perth Basins in Western Australia have been identified among the key locations most likely to hold commercial shale gas deposits (Cook et al. 2013). The Perth Basin has prospective targets in the marine shales of the Upper Permian Carynginia Formation and Triassic Kockatea Shale. The Triassic Kockatea shale Formation is one of the source rocks and it consists of dark shale, micaceous siltstone along with minor sandstone and limestone. The Ordovician Goldwyer Formation is the main source rock in the Canning Basin and it varies from mudstone dominated in basinal areas to limestone-dominated in some platform and terrace areas.