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.
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.
This paper demonstrates the ability of a 2D independent two-phase flow hydro-mechanical (H-M) simulator, FLAC (Fast Lagrangian Analysis of Continua), to predict H-M responses related to Co2 injection in subsurface disposal reservoirs. This is the first paper to study the use of FLAC as a single H-M simulator for Co2 injection processes. The models in FLAC are tested against twoexistingmodels: (1)a prototype Co2injectionreservoirand(2)the InSalahgas fieldinAlgeria.The H-M responses such as the spread of Co2 plumes, the history of pore pressure increases, and surface uplifts are presented and compared with the results from the reference models. The potential for mechanical failures and leakage are also analyzed using critical pressure approach. The simulations show that FLAC models are able to capture typical shapes of Co2 plumes in the reservoirs. The history of pore pressure increase and a typical bell-shape for surface uplifts are obtained. The potential location for mechanical failures and leakage is also well predicted. Future implementation of H-M stress-dependent properties in FLAC will improve its capability. Hence, coupling this software with other fluid flow simulator such in the literatures may no longer be necessary in the future.
In this work, we present results of coupled fluid flow and geomechanical modeling associated with the Co2 injection at three different wells (KB-501, KB-502, KB-503) at In Salah, Algeria. Our recent numerical studies focused on the KB- 502 Co2 injection well, where a double-lobe uplift pattern has been observed in the ground-deformation data. The observed uplift patterns at KB-501 and KB-503 are different, with no clear influence of deep fracture zone mechanical response. In this study we improved our modeling with TOUGH-FLAC considering inelastic deformations in the injection zone, which responds to a Mohr- Coulomb failure criterion. For the case of KB-502 we introduced a fracture zone, modeled as in past considering inelastic deformations, but including a more detailed failure criterion. In addition, we modeled a stress-dependent permeability and bulk modulus, according to a dual continuum model. Mechanical and hydraulic properties of the injection reservoir and those of fracture zones at the three injection wells were determined through inverse modeling with iTOUGH2 by matching the simulated spatial and temporal evolution of uplift to the corresponding InSAR observations as well as by matching simulated and measured pressures. We found an excellent match between simulated and observed variables, with residuals well within the limit of the observation errors. The estimated values for the parameterized mechanical and hydraulic properties are in good agreement with previous numerical results.