Several approaches that use the activity coefficient model assume the oil and asphaltene as two pseudocomponents: one component representing the deasphalted oil and the other the asphaltenes. Andersen and Speight provided a review of activity models in this category. Other approaches represent the precipitate as a multicomponent solid. Chung, Yarranton and Masliyah, and Zhou et al. gave detailed descriptions of these models. The solubility model used most in the literature is the Flory-Huggins solubility model introduced by Hirschberg et al. Vapor/liquid equilibrium calculations with the Soave-Redlich-Kwong EOS are performed to split the petroleum mixture into a liquid phase and a vapor phase.
In some reservoir applications, seismic data are acquired with downhole sources and receivers. If the receiver is stationed at various depth levels in a well and the source remains on the surface, the measurement is called vertical seismic profiling (VSP). This image, a 2D profile restricted to the vertical plane passing through the source and receiver coordinates, is useful in tying seismic responses to subsurface geologic and engineering control. If the source is deployed at various depth levels in one well and the receiver is placed at several depth stations in a second well, the measurement is called crosswell seismic profiling (CSP). Images made from CSP data have the best spatial resolution of any seismic measurement used in reservoir characterization because a wide range of frequencies is recorded.
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.
Sazali, Wan Muhammad Luqman (Petronas Research Sdn. Bhd.) | Md Shah, Sahriza Salwani (Petronas Research Sdn. Bhd.) | Kashim, M. Zuhaili (Petronas Research Sdn. Bhd.) | Kantaatmadja, Budi Priyatna (Petronas Research Sdn. Bhd.) | Knuefing, Lydia (Australian National University) | Young, Benjamin (Thermo Fisher Scientific)
PETRONAS is interested in monetizing X Field, a high CO2 carbonate gas field located in East Malaysian waters. Because of its location (more than 200 km from shore) and the preferable geological formation of the field, reinjection of produced CO2 back into the field's aquifer has been considered as part of the field development plan. To ensure feasibility, the PETRONAS R&D team has conducted a set of laboratory analyses to observe the impact of CO2 on the carbonate formations, through combining the use of static CO2 batch reaction experiments with advanced helical digital core analysis techniques. The analysis of two representative samples, from the aquifer zone is presented here. The initial state of the samples was determined through the use of theoretically exact helical micro computed tomography (microCT) techniques. The images were processed digitally to determine the porosity and calibrated with RCA to ensure the reliability of digital core analysis results. After scanning, both plugs were saturated with synthetic brine with similar composition as the fields' formation brine and aged with supercritical CO2 at reservoir temperature and pressure for 45 days. After 45 days, the aged core plugs underwent post reaction analysis using micro-CT scan and image processing software. Based on macroscopic observation, the core plugs showed no changes after aging with supercritical CO2 at high pressure and high temperature (HPHT) as per reservoir condition. However, analysing the high resolution micro CT images, the team was able to determine the changes in porosity before and after CO2 aging, which are around 1%.
Olalotiti-Lawal, Feyi (Texas A&M University) | Onishi, Tsubasa (Texas A&M University ) | Kim, Hyunmin (Texas A&M University ) | Datta-Gupta, Akhil (Texas A&M University ) | Fujita, Yusuke (JX Nippon Oil & Gas Exploration Corporation) | Hagiwara, Kenji (JX Nippon Oil & Gas Exploration Corporation)
We present a simulation study of a mature reservoir for carbon dioxide (CO2) enhanced-oil-recovery (EOR) development. This project is currently recognized as the world’s largest project using post-combustion CO2 from power-generation flue gases. With a fluvial formation geology and sharp hydraulic-conductivity contrasts, this is a challenging and novel application of CO2 EOR. The objective of this study is to obtain a reliable predictive reservoir model by integrating multidecadal production data at different temporal resolutions into the available geologic model. This will be useful for understanding flow units along with heterogeneity features and their effect on subsurface flow mechanisms, to guide the optimization of the injection scheme and maximize CO2 sweep and oil recovery from the reservoir.
Our strategy consists of a hierarchical approach for geologic-model calibration incorporating available pressure and multiphase production data. The model calibration is performed using regional multipliers, and the regions are defined using a novel adjacency-based transform accounting for the underlying geologic heterogeneity. The genetic algorithm (GA) is first used to match 70-year pressure and cumulative production by adjusting pore volume (PV) and aquifer strength. Water-injection data for reservoir pressurization before CO2 injection is then integrated into the model to calibrate the formation permeability. The fine-scale permeability distribution consisting of more than 7 million cells is reparameterized using a set of linear-basis functions defined by a spectral decomposition of the grid-connectivity matrix (Laplacian grid). The parameterization represents the permeability distribution using a few basis-function coefficients that are then updated during history matching. This leads to an efficient and robust work flow for field-scale history matching.
The history-matched model provided important information about reservoir volumes, flow zones, and aquifer support that led to additional insight compared with previous geological and simulation studies. The history-matched field-scale model is used to define and initialize a detailed fine-scale model for a CO2 pilot area that will be used to study the effect of fine-scale heterogeneity on CO2 sweep and oil recovery. The uniqueness of this work is the application of a novel geologic-model parameterization and history-matching work flow for modeling of a mature oil field with decades of production history, and which is currently being developed with CO2 EOR.
Enhanced oil recovery (EOR) from heavy oil reservoirs is challenging. The higher viscosity of oil in such reservoirs, add more challenges and severe the difficulties during any EOR method (i.e. high mobility ratio, inadequate sweep, reservoir heterogeneity) compared to that of EOR from light oil reservoirs. Foam has gained interest as one of the EOR methods especially for challenging and heterogeneous reservoirs containing light oil. However, the foam and especially polymer enhanced foam (PEF) potential for heavy oil recovery is less studied.
The current study aims to evaluate the performance of CO2 foam and CO2 PEF during heavy oil recovery from both unconsolidated (i.e. sandpack) and consolidate (rock sample) porous media with the help of fluid flow experiments. The injection pressure profile, oil recovery, and CO2 gas production were monitored and recorded to analyze and compare the performance of CO2 foam and PEF for heavy oil recovery. A visual sandpack made of glass column and a core-flood system capable of measuring the pressure at different sections of the core were used in this study. Homogenous and fractured sandstone core samples, as well as a fractured carbonate core sample, were selected for the core-flood study.
Static stability results revealed slower liquid drainage and collapse rates for PEF compared to that of foam even in the presence of heavy crude oil. The addition of polymer significantly improved the performance of CO2 foam flooding during heavy oil recovery in dynamic experiments. This result was inferred from faster propagation rate, higher dynamic stability, and higher oil recovery of CO2 PEF over CO2 foam injection. Moreover, the visual analysis demonstrated more stable frontal displacement and higher sweep efficiency of PEF compared to the conventional foam flooding. In the fractured porous media, additional heavy oil recovery was obtained by liquid diversion into the matrix area rather than gas diversion inferred from pressure profile and gas production data.
The results obtained from this study show that CO2 PEF could significantly improve the heavy oil recovery and CO2 sequestration, especially in homogeneous porous media.
Franklin M. Orr Jr., Stanford University Summary Recent progress in carbon capture, utilization, and storage (CCUS) is reviewed. Considerable experience has now been built up in enhanced-oil-recovery (EOR) operations, which have been under way since the 1970s. Storage in deep saline aquifers has also been achieved at scale. Introduction The challenge of making deep reductions in greenhouse gas (GHG) emissions in this century is a daunting one given the scale of the use of energy by humans and our current dependence on fossil fuels, which provide essential energy services at low cost to modern societies. Meeting the challenge of reducing GHG emissions will require a fully diversified portfolio of approaches, such as much more energy-efficient end-use technologies (e.g., cars, home and business heating and air conditioning, lighting); electrification of energy services coupled with reduced GHG emissions from electric power generation; fuel switching in transportation and electric power generation; deployment of additional renewable power generation; land-use changes toward lower-emission agriculture; emission reductions of short-term forcers such as black carbon, CH Integrated assessments of the various pathways indicate that portfolios that include significant deployment of CCUS have lower estimated costs than those without CCUS (Clarke et al. 2014; Krey et al. 2014). In 2005, the Intergovernmental Panel on Climate Change (IPCC) issued a detailed special report (SRCCS) on many aspects of carbon capture and storage (CCS) (Metz et al. 2005). Wilcox (2012) provided detailed descriptions of specific capture technologies and their energy requirements, as did Boot-Handford et al. (2014), who gave additional commentary on pipeline transportation issues, subsurface storage issues, and a European policy perspective.
Al-Zaabi, Fatema (ADNOC Offshore) | Amer, Mohamed (ADNOC Offshore) | Al-Jaberi, Salem (ADNOC Offshore) | Afzal, Nusrat (ADNOC Offshore) | Abdelbagi, Mohamed (ADNOC Offshore) | Deng, Lichuan (Baker Hughes, a GE Company) | Soliman, Ahmed (Baker Hughes, a GE Company) | Kieduppatum, Piyanuch (Baker Hughes, a GE Company) | Bhatt, Pranjal (Baker Hughes, a GE Company) | Fernandes, Warren (Baker Hughes, a GE Company)
Reservoir A is an Upper Jurassic reservoir in offshore Abu Dhabi, composing layers of dense anhydrite and porous mixed lithology of dolomite and limestone. Petrophysical study from multiple wells suggests that the rock quality within the reservoir has significant lateral and vertical variations that can result in different flow capacities. Consequently, it is crucial to identify the rock quality variations and the consequent flow capacity in horizontal wells to optimize development plan, ideally in real-time. However, these lateral and vertical variations are not visible from conventional porosity (density / neutron) logs, making identification of rock quality very challenging. This paper introduces an innovative magnetic resonance (NMR)-based real-time method of permeability prediction and rock typing.
Wireline logs including NMR were acquired in a pilot well, providing porosity and extensive T2-based information (permeability index, irreducible and movable fluid volume and porosity partition). Routine core analysis was also available to calibrate the NMR data, achieving a suitable correlation for NMR permeability index calibration in this field. Several rock types could be identified with the Windland R35 technique using porosity and calibrated permeability from NMR. This identification was then validated by rock types from cores. The application of knowledge gained from the study led to advanced reservoir characterization solely based on the NMR log. The process was applied to high-angle and horizontal (HAHZ) wells where the NMR full-spectrum log while drilling was available.
Several slanted wells were drilled with a fit-for-purpose logging-while-drilling (LWD) suite including NMR for geo-steering and formation evaluation. The real-time LWD NMR data helped trace a remarkable change of irreducible water level through certain layers, suggesting that the subzones of Reservoir A changed pore geometry and rock type laterally, resulting in variations of flow capacity and reservoir performance.
In one example, this method indicated unexpected good rock quality in one of these subzones considering the experience from offset well. Subsequently, the LWD formation-testing tool confirmed the result with mobility measurements, proving the NMR-based methodology was valid.
This process normally applies to memory data after drilling, playing a key role in designing completion strategy in a timely manner. The process is also available in real-time while drilling if full NMR data is transmitted to surface, serving as a safer logging-tool for identification of sub-zones with additional valuable information compared to regular porosity tools with chemical radioactive source.
Yu, Hongyan (Northwest University) | Zhang, Yihuai (Curtin University) | Lebedev, Maxim (Curtin University) | Wang, Zhenliang (Northwest University) | Verrall, Michael (CSIRO) | Iglauer, Stefan (Edith Cowan University)
Carbon dioxide (CO2) inject to the saline aquifers are general considered as the best candidates for large-scale storage and CO2 enhance oil recovery. The pore structure and permeability are changed by the fines release, migration in the initial stage of CO2 injection, which is of great importance for reservoir screening and injection design requires adequate understanding. We thus imaged an unconsolidated sandstone at reservoir condition before and after live brine injection in situ with micro-CT core flooding apparatus. We conclude that the pore structure of the unsolid high pores media rock can be significantly changed after live brine injection, although the porosity just have a small increased. Meanwhile, many fractures are generated in the quartz after live brine flush away. Specific surface area are quantified from micro CT scan image analysis to calculate the absolute permeability. The permeability is significantly improved due to the pore structure change which can improve CO2 infectivity, especially low-permeability reservoirs. The results of this study present a broad characterization of the mechanical properties in lacustrine shale and can therefore help optimize hydraulic fractured fundamental and enhanced gas recovery.
Al Ramadhan, Abdullah (EXPEC Advanced Research Center, Saudi Aramco) | Hemyari, Emad (EXPEC Advanced Research Center, Saudi Aramco) | Bakulin, Andrey (EXPEC Advanced Research Center, Saudi Aramco) | Erickson, Kevin (EXPEC Advanced Research Center, Saudi Aramco) | Smith, Robert (EXPEC Advanced Research Center, Saudi Aramco) | Jervis, Michael A. (EXPEC Advanced Research Center, Saudi Aramco)
In 2015, Saudi Aramco started a CO2 Water-Alternating-Gas (WAG) EOR pilot project in an onshore carbonate reservoir. To monitor lateral expansion of the CO2 plume, the area was instrumented with a hybrid surface/downhole permanent seismic monitoring system. This system consists of over 1000 buried seismic sensors at a depth of around 70 m, below the the depth of expected weathering layer to mitigate the time-lapse noise. Despite receiver burial, seismic data still suffers from numerous challenges including: significant amounts of high-amplitude coherent noise such as guided waves, mode conversions, and scattered energy; amplitude variations over space and time caused by source and receiver coupling; variability of wavelet shape and arrival times due to seasonal near-surface variations; and low signal-to-noise ratio (SNR). A novel processing workflow was designed for 4D processing of such data. The workflow involves five critical processes. First, the high-amplitude coherent noise is eliminated using FK-based techniques that are 4D compliant to preserve the reservoir changes between repeated seismic surveys. Second, a four-term joint surface-consistent amplitude-scaling algorithm resolves the amplitude variations. The algorithm allows both source and receiver terms to have different scalars for the same positions, but it restricts the other two terms to be position-invariant over different time-lapse surveys, as the window of analysis does not include the reservoir. This is to guarantee that the source and receiver terms are survey-dependent while the other two terms are survey-independent. Thus, the amplitude variability is linked to source and receiver positions over space and time. It also assures that the reservoir changes are not affected by changes in the overburden. Third, wavelet shape variations are addressed using a four-term joint surface-consistent spiking deconvolution algorithm that applies similar principle as the scaling algorithm. Fourth, the small variations in reflection times between different surveys (4D statics) caused by seasonal variations are corrected by a specialized surface-consistent residual statics algorithm using a common pilot derived from the base survey. Fifth, the pre-stack data is supergrouped to enhance the signal-to-noise ratio and repeatability.
The processing workflow has been applied to frequent land 3D seismic data acquired over a CO2 WAG EOR pilot project in Saudi Arabia. As a result, we obtained very repeatable seismic images that may successfully detect small CO2-related changes in a stiff carbonate reservoir.