Africa (Sub-Sahara) Kosmos Energy has made a significant deepwater gas discovery off Senegal. The Guembeul-1 well in the northern part of the St. Louis Offshore Profond license in 8,858 ft of water encountered 331 net ft of gas pay in two excellent-quality reservoirs, the company reported. The results demonstrate reservoir continuity and static pressure communication with the Tortue-1 well, which suggests a single gas accumulation. The mean gross resource estimate for the Greater Tortue complex has risen to 17 Tcf from 14 Tcf as a result of the Guembeul discovery, the company said. Kosmos, the operator, has a 60% interest in the well. Timis (30%) and Petrosen (10%) hold the remaining interest. In Salah Gas has started production from its Southern fields in Algeria.
Learn more about training courses being offered. Learn more about training courses being offered. This course covers the fundamental principles concerning how hydraulic fracturing treatments can be used to stimulate oil and gas wells. It includes discussions on how to select wells for stimulation, what controls fracture propagation, fracture width, etc., how to develop data sets, and how to calculate fracture dimensions. The course also covers information concerning fracturing fluids, propping agents, and how to design and pump successful fracturing treatments. Learn more about training courses being offered. Current and future SPE Section and Student Chapter leaders are invited to engage and share. Every attendee leaves energised with a full list of ideas and a support network of fellow leaders. Those sections and student chapters actively participating in this workshop have consistently been recognized with awards as the best in SPE. SPE Cares is a global volunteering drive aimed at promoting, supporting and participating in community services at the SPE section and student chapter’s level. On its official launch this year at ATCE Dubai, SPE Cares will conduct a “Give a Ghaf” Tree Planting Programme to help preserve Ghaf’s cultural and ecological heritage. The Ghaf tree is an indigenous species, specific to UAE, Oman and Saudi Arabia. It is a drought tolerant, evergreen tree that can survive a harsh desert environment. The initiative not only aims to hold events/activities at ATCE, but also recognise community service that SPE members are already conducting in their respective student chapters and professional sections. The KEY Club, open daily, is an exclusive lounge for key SPE members. The lounge is open to those with 25 years or more of continuous membership, Century Club members, current and former SPE Board officers and directors, Honorary and Distinguished Members, as well as this year’s SPE International Award Winners and Distinguished Lecturers. DSATS (SPE’s Drilling Systems Automation Technical Section) will hold a half-day symposium featuring keynote presentations on urban automation. This symposium will explore technologies being used in developing smart cities through the automation of their infrastructure, transportation systems, energy distribution, water systems, street lighting, refuse collection, etc. These efforts rely on many of the same tools needed for drilling systems automation yielding increased efficiencies, lower maintenance and reduced emissions. Their knowledge and experience can guide the path being travelled by the oilfield drilling industry.
Mechanical failure of cap rock is one of the main reasons of CO2 leakage from the storage formations. Through comprehensive assessment on the petrophysical and geomechanical heterogeneities of cap rock, it is possible to estimate the pressure distribution more accurately and to predict the risk of unexpected caprock failure. To describe the fracture reactivation and fracture permeability, modified Barton-Bandis model and dual permeability system are applied. Porosity-permeability relationship is calculated with power law. In order to generate hydro-geomechanically heterogeneous fields, the negative correlation between porosity and Young's modulus/Poisson's ratio is applied. In comparison to homogeneous model, effects of heterogeneity are examined in terms of vertical deformation and the amount of leaked CO2. To compare the effects of heterogeneity, heterogeneous models for both geomechanical and petrophysical properties in coupled simulation are designed.
Simulation results show that CO2 leakage occurs after 4-6 years from injection. After 10 year injection with petrophysically heterogeneous and geomechanically homogeneous caprock, CO2 leakage is larger than that of homogeneous model. In contrast, heterogeneity of geomechanical properties is shown to mitigate additional escape of CO2. Vertical displacement of every heterogeneous model is larger than homogeneous model. According to results from model with petrophysically heterogeneous and geomechanically homogeneous caprock, the higher Dykstra-Parsons coefficients (
Min, Baehyun (The University of Texas at Austin) | Nwachukwu, Azor (The University of Texas at Austin) | Srinivasan, Sanjay (Pennsylvania State University) | Wheeler, Mary F. (The University of Texas at Austin)
A model selection process based on multi-objective optimization using a fast proxy is presented that chooses geologic models conditioned to observed flow and geomechanical responses. The responses of geologic models to injection of large volumes of CO2 are evaluated using a proxy that approximates pressure distribution using a random walk particle tracking algorithm and computes surface deformation using a stress-field solver. The geologic models showing similar proxy responses are grouped into clusters by invoking multi-dimensional scaling and
ABSTRACT: A coupled flow-geomechanical modelling study has been carried out in an effort to match the flowing bottomhole pressures and InSAR surface uplift time series at the three injection wells over the seven years CO2 injection period at In Salah. The surface deformation data covers the entire period of monitoring from July 2003 to January 2012. It is believed that a structural feature controls the dynamic pressure and geomechanical behaviour at both injection wells KB-502 and KB-503, and that CO2 injection has caused tensile opening of pre-existing fractures/faults in the area. This insight was incorporated by introducing a fracture/fault zone with a dynamic transmissibility into the coupled flow-geomechanical model. Using forward coupled flow- geomechancial modelling, both the injection pressure behaviour and the geomechanical response at the ground surface have been largely reproduced. Research findings helped assess the overall performance of the site and potential for the migration of CO2 within the storage complex.
A growing concern that the ongoing increase in atmospheric concentrations of the greenhouse gas carbon dioxide (CO2) is contributing to global climate change has led to a search for technologies to reduce CO2 emissions. For this purpose, Carbon Capture and Storage (CCS) has been proposed as a promising technology to reduce CO2 emissions produced by the combustion of fossil fuels (IPCC 2005). The concept of CCS involves capturing CO2 from fossil fuel combustion, compression, transport and injection into a deep geological formation.
Research carried out in association with the four major industrial scale projects Sleipner and Snøhvit in Norway (Eiken et al. 2011, Chadwick et al. 2012, Shi et al. 2013a), In Salah in Algeria (Ringrose et al. 2009) and Weyburn in Canada (White 2009), together with smaller but equally valuable research pilots such as Ketzin in Germany (Liebscher et al. 2013) and Otway in Australia (Jenkins et al. 2012) have improved our understanding of the subsurface processes involved in CO2 storage a great deal and helped develop storage performance and risk assessment methodologies. The experience gained from these projects have shown that fluid behaviour and the geomechanical response of the CO2 storage formation and surrounding structures are some of the critical parameters that will determine the overall system performance. Real sites may contain features, such as non-sealing wells, faults, fracture zones, which may allow CO2 to migrate and leak out of the storage reservoir. Furthermore, increases in reservoir pressure in response to CO2 injection would induce mechanical stresses and deformation in and around the injection reservoir. Moreover, there is also a potential to induce seismicity on nearby faults. If reservoir pressure increase becomes too large, the induced stresses may cause irreversible mechanical changes, creating new fractures or reactivating preexisting ones, compromising the storage integrity of the reservoir.
Pore pressure reduction due to hydrocarbon extraction from gas reservoirs causes compaction of the reservoir rock accompanied by a redistribution of stresses in the surrounding rock mass, leading to sub-surface deformations and surface subsidence. There is evidence to suggest that the induced sub-surface movements in some of the Netherlands’ gas fields (the motivation behind the study) are time-varying. The sandstone reservoirs in question are overlain by relatively thick layers of rocksalt, which flows viscoelastically when shear stress are applied to it. For this reason, rocksalt flow has been proposed as a mechanism to explain the observed time-dependence. The work reported here aims to understand the mechanisms by which viscoelastic rocksalt flow can cause surface displacements and to assess whether the magnitude of the resulting displacements can be significant over timescales similar to those observed in the field. Finite Element analyses of idealized reservoir geometries and simplified geological models will be employed for this purpose, with the aim of avoiding complexities that can mask the underlying processes and phenomena. Results here indicate that salt-driven flow has the potential of inducing significant timedependent subsidence, in excess to the ones calculated through solely elastic analyses of the same problem. They therefore indicate that in cases where accurate subsidence predictions are essential, salt has to be modeled accurately.
Extraction of natural gas from a reservoir rock formation leads to pore-fluid pressure decrease and so an effective stress increase in the reservoir rock. This in turn leads to reservoir compaction which is registered at the surface as subsidence. The link between production-induced pore pressure changes at the reservoir level and surface subsidence is well-established, e.g. [1, 2, 3, 4].
In many cases the ground is modelled as elastic and so an immediate subsidence response to the pore pressure reduction is expected at the surface (after [5, 6]). This thinking therefore assumes that subsidence stops immediately after the stop of production from a reservoir. However there is growing evidence to suggest that for some reservoirs there is a delay in the subsidence response, i.e. a time-dependence of ground deformations, see [7, 8].
Zhang, Y. (CSIRO Minerals) | Schaubs, P. M. (CSIRO Minerals) | Langhi, L. (CSIRO Energy) | Delle Piane, C. (CSIRO Energy) | Dewhurst, D. N. (CSIRO Energy) | Stalker, L. (CSIRO Energy) | Michael, K. (CSIRO Energy)
An area in the Southern Perth Basin has been identified as a potentially suitable site for CO2injection, due to its proximity to major CO2emission sources and the presence of potentially suitable geology. The project for testing and proving up of the storage area is known as the South West Hub Project or SW Hub. Recently acquired 2D seismic and well data have allowed a detailed description of facies, measurement of rock properties and development of a 3D structural model for the area. This 3D model has been used as the basis for a preliminary fault seal analysis and also for the development of simplified geomechanical models for the SW Hub using FLAC3D. The geomechanical modelling used in situ stress (magnitude, orientation) and pore pressure conditions as a starting point and then simulated CO2injection from a single well at rates of 1 to 5 million tons per year for 20 years. No matter whether weak or strong faults were used, no faults were reactivated nor the top seal breached under any of the simulated injection rates. Average uplift in the weak fault scenario was modelled at between 0.4 and 1.8 cm for injection rates of 1 to 5 million tons per year. The strong fault model showed slightly smaller uplifts. The majority of uplift was noted in the first 5 years of injection and flattened off rapidly after this point in time. This is consistent with geomechanical models from other CO2storage sites and from actual field measurements.
Suitable geology and proximity to large sources of carbon dioxide led to the Southern Perth Basin being investigated as a potential geological storage site . The specific area selected is in the region of the Harvey- 1 well (Figure 1) around 150 km south of Perth in Western Australia. This has become known as the South West Hub project and this area is currently undergoing extensive site assessment in terms of reservoir quality, containment potential, structural geology, facies analysis, rock properties and the like.
We demonstrate a workflow to simulate seismicity generated by CO2 injection into the In Salah field, Algeria. Seismic activity in hydrocarbon reservoirs is caused by stress changes on pre-existing fractures that lead to their re-activation. As inputs to our workflow, a history-matched reservoir flow simulation is used to model changes in pressure caused by injection; while a geomechanical model gives the stress state at each node of the flow model. The locations, lengths, and orientations of pre-existing fractures in the reservoir are modeled via a mass-spring solver, which restores the faulted, folded reservoir to its initial, undeformed conditions. This algorithm predicts the intensity and orientation of strain through the model, from which fracture sets can be generated. To simulate seismicity during CO2 injection, we compute changes in effective stress caused by pore pressure changes, and map these stress changes into shear and normal stresses acting on the fractures. Where stresses exceed Mohr-Coulomb failure criteria, seismic events are predicted. We compare our modeled events with observed seismicity at In Salah, finding excellent agreement between model and observation in terms of event timing, event location, and event magnitude.