Jia, Ying (Petroleum Exploration and Production Research Institute, SINOPEC) | Shi, Yunqing (Petroleum Exploration and Production Research Institute, SINOPEC) | Huang, Lei (Research Institute of Petroleum Exploration and Development, Petrochina) | Yan, Jin (Petroleum Exploration and Production Research Institute, SINOPEC) | Sun, Lei (SouthWest Petroleum University)
The YKL condensate gas reservoir is one of the biggest condensate gas reservoirs in China and has been developed more than 10years. At present, the combination of subdivision layer, production speed optimization and horizontal well drilling has been the key to economically unlocking the vast reserves of the YKL condensate gas. The primary recovery factor, however, remains rather low due to high capillary trapping and water invasion. While primary depletion could result in low gas recovery, CO2 flooding provides a promising option for increasing the recovery factor.
The objective of this work is to verify and evaluate the effect supercritical CO2 on enhancing gas recovery and analyze the feasibility of CO2 enhance gas recovery (CO2 EGR) of condensate gas reservoir.
Firstly, novel phase behavior experimental procedures and phase equilibrium evaluation methodology for gas-condensate phase system mixed with supercritical CO2 with high temperature were presented. A unique phase behavior phenomena was also reported. Then, CO2 floodingmechanism in condensate gas reservoir was analyzed and clarified based on experiments. Finally, a series of numerical simulation work were conducted as an effective and economical means to maximize natural gas recovery with the lowest CO2 breakthrough by varying strategies, including CO2 injection rate, injection composition, andinjection timing. Meanwhile the CO2 storage volumes of different strategies were calculated.
The results show that higher gas recovery factor can be achieved with CO2 injection through appearing interphase between two fluids, maintaining reservoir pressure, driving gas like "cushion" and controlling water invasion. All strategies have moderate to significant effects on gas production. The control of injection and production ratio needs to be balanced between pressure transient and CO2 breakthrough over the producer to obtain the maximum gas production. The varying injection pressure shows a positive effect of enhancing gas production. Numerical simulation indicated that the recovery of gas reservoir was improved by around 10 percent. The total CO2 storage would be around 30-40% HCPV.
The research showed that CO2 flooding presents a technically promising method for recovering the vast condensate gas while extensively reducing greenhouse gas emissions.
The SWP project is located in a mature waterflood undergoing conversion to CO2-WAG operations at Farnsworth, Texas, USA. Utilized CO2 is anthropogenic, sourced from a fertilizer and an ethanol plant. Major project goals are optimizing the storage/production balance, ensuring storage permanence, and developing best practices for CCUS.
This paper provides a review of work performed toward development of a 3D coupled Mechanical Earth Model (MEM) for use in assessment of caprock integrity, fault reactivation potential, and evaluation of stress dependent permeability in reservoir forecasting. Mechanical property estimates computed from geophysical logs at selected wellbores were integrated with 3D seismic elastic inversion products to create a 3D "static" mechanical property model sharing the same geological framework as the existing reservoir simulation model including 3 major faults. Stresses in the MEM were initialized from wellbore stress estimates and reservoir simulation pore pressures. One way and two way coupled simulations were performed using a compositional hydrodynamic flow model and geomechanical solvers.
Coupled simulations were performed on history matched primary, secondary (waterflood), and tertiary (CO2 WAG) recovery periods, as well as an optimized WAG prediction period. These simulations suggest that the field has been operating at conditions which are not conducive to either caprock failure or fault reactivation. Two way coupled simulations were performed in which permeability was periodically updated as a function of volumetric strain using the Kozeny-Carmen porosity-permeability relationship. These simulations illustrate the importance of frequent permeability updating when recovery scenarios result in large pressure changes such as in field re-pressurization through waterflood after a long primary depletion recovery period. Conversely, production forecasting results are less sensitive to permeability update frequency when pressure cycles are short and shallow as in WAG cycles.
This paper describes initial work on development of a mechanical earth model for use in assessment of geomechanical risks associated with CCUS operations at FWU. The emphasis of this work is on integration of available geomechanical data for creation of the static mechanical property model. Preliminary coupled hydro-mechanical simulations are presented to illustrate some of the key diagnostic output from coupled simulations which will be used in later work for in depth evaluation of specific risk factors such as induced seismicity and caprock integrity.
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].