Kashim, Muhammad Zuhaili (PETRONAS) | Giwelli, Ausama (CSIRO) | Clennell, Ben (CSIRO) | Esteban, Lionel (CSIRO) | Noble, Ryan (CSIRO) | Vialle, Stephanie (Curtin University) | Ghasemiziarani, Mohsen (Curtin University) | Saedi, Ali (Curtin University) | Md Shah, Sahriza Salwani (PETRONAS) | M Ibrahim, Jamal Mohamad (PETRONAS)
In line with PETRONAS commitment to monetize high CO2 content gas field in Malaysia, C Field which is a carbonate gas field located in East Malaysia's waters with approximately 70% of CO2 becomes main target for development because of its technical and economic feasibility. Injectivity has been determined as one of the key parameters that determine the success of CO2 storage in field operations. In order to characterize the CO2 injecitivity behavior in C Field, long duration coreflooding experiments has been conducted on two representative core samples under reservoir conditions. The first set of coreflooding test has been conducted on gas zone sample and another one is on aquifer sample. Two important approach has been applied in the experiment in which the first one is where the base rate is established after each incremental stage and the second one is the pre-equilibration of carbonated brine with standard minerals based on the percentage of core mineralogy before saturating the core with aquifer brine to mimic the insitu geochemical conditions of the reservoir. Pre- and post-flooding characterization was conducted using Routine Core Analysis (RCA), X-Ray CT-scan, Nuclear Magnetic Resonance (NMR) and Inductive Coupled Plasma (ICP) to examine the porosity-permeability changes, pore size alterations and the geochemical processes that might take place during CO2 flooding. Based on the differential pressure data, it showed no clear indication of formation damage even after injection of large CO2 pore volume. Pre and post-flooding characterization supported the findings where minor dissolution/precipitation is observed. Overall intrepretation indicates that the critical flowrate is not yet reached for both samples within the maximum rates applied.
Yu, Hongyan (State Key Laboratory of Continental Dynamics) | Li, Xiaolong (Department of Geology, Northwest University) | Wang, Zhenliang (State Key Laboratory of Continental Dynamics) | Rezaee, Reza (Department of Geology, Northwest University) | Gan, Litao (Northwest University)
Abundant shale oil and gas resources have been discovered in the Zhangjiatan shale of the Yanchang formation in ordos basin in recent years. Zhangjiatan shale is a typical lacustrine shale, which is different from Marine shale in physical properties. Most previous research has focused on Marine shale. In order to understand the rock mechanical properties of Zhangjiatan shale, we conducted dynamic and static elastic properties experiments. We selected argillaceous shale and silty laminae shale in Zhangjiatan shale as samples. In order to obtain the static Young's modulus and Poisson's ratio, we use the triaxial pressure test. We use the dipole log to measure the acoustic velocity down the hole, and then we calculate the dynamic Young's modulus and Poisson's ratio of the sample based on acoustic velocity. Young's modulus of argillaceous shale is slightly smaller than that of silty laminae shale and the Poisson's ratio of argillaceous shale is also smaller than that of silty laminae shale. The brittleness of argillaceous shale are greater than that of silty laminae shale, as a result, argillaceous shale is much easier fracturing under pressure. We plotted the cross-plot of RCS, elastic properties and TOC and reached a conclusion that the mass ratio of clay to quartz and feldspar determined the brittleness and deformability of rock, while organic matters also affected the elastic properties of rock. Therefore, the elastic properties of shale are not controlled by a single factor, instead of multiple factors.
Hydraulic fracturing is considered to be a vital cornerstone in decision making of unconventional reservoirs. With an increasing level of development of unconventional reservoirs, many questions have arisen regarding enhancing production performance of tight carbonate reservoirs, especially the evaluation of the potential for adapting multistage hydraulic fracturing technology in tight carbonate reservoirs to attain an economic revenue.
In this paper we present a feasibility study of multistage fractured horizontal well in typical tight carbonate reservoirs covering different values of permeability. We show that NPV is the suitable objective function for deciding on the optimum number of fractures and fracture half-length. Multistage fractured horizontal well has been found to be a feasible technique to produce from tight carbonate reservoirs with permeability in the range of 0.01-0.05 mD, while it is not economic reservoirs with permeability of around 0.001 mD. In addition, our study suggests that for feasibility study purposes simplified homogeneous reservoir models can be used instead of a heterogeneous one without compromising the quality of conclusions. This will save time, money and efforts in evaluating production performance of various options like, number, length and other fracture properties of multistage fractured horizontal wells.
Distributed Acoustic Sensing (DAS), as a seismic sensor, has unique features allowing us to record multiple datasets with variable acquisition parameters set inside the recording box, while using one continuous recording cable and a single round of shooting. We reveal how these distinct features allow DAS to deliver multi-scale data and have the capability to focus on both the near surface and deeper targets simultaneously. We present synthetic and field examples of "deep" and "shallow" DAS surveys and demonstrate their effectiveness. The new capabilities of surface seismic with DAS technology comprise a sensing revolution that addresses long-standing near-surface issues in land seismic without compromising the deeper imaging. Achieving similar capabilities with point sensors could be done but would lead to ballooning acquisition costs, whereas surface seismic with DAS can deliver them at a cost less than conventional geophone acquisition available today.
Reservoir heterogeneity plays a critical role in determining the success of enhanced-oil-recovery (EOR) processes, but its effect rarely has been comprehensively quantified in the laboratory. This work presents the results of an experimental study on the effects of various carbon dioxide (CO2) injection modes on immiscible-flooding performance in heterogeneous-sandstone porous media. Thus, the results of this study can be insightful in overcoming the current challenges in capturing the importance of geological uncertainties in current and future EOR projects.
Coreflooding experiments were conducted for n-decane/synthetic-brine/CO2 systems at a 9.6-MPa backpressure and at 343 K to attain immiscible-flooding conditions [minimum-miscibility pressure (MMP) of CO2 in n-decane is 12.4 MPa]. For this purpose, two sets of heterogeneous-sandstone core samples were assembled with heterogeneity either parallel to (layered samples) or perpendicular to (composite samples) the flow. The results obtained for both composite and layered core samples indicated that heterogeneity tremendously influences the outcome of the CO2 EOR. Oil recovery decreases dramatically with an increase in the heterogeneity level or permeability ratio (PR). In addition, the crossflow in the layered core sample is found to have a noticeable effect on the ultimate oil recovery (increasing oil recovery up to 5%). Also, it is worth noting that for the composite samples, when we arranged the plugs by putting the low-permeability segments closer to the sample outlets, the recovery factor increased. However, regardless of the segment arrangements, the recoveries in composite cores are lower than those obtained from the homogeneous core sample.
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-Anssari, Sarmad (Curtin University, University of Baghdad, Edith Cowan University) | Arain, Zain-UL-Abedin (Curtin University) | Barifcani, Ahmed (Curtin University) | Keshavarz, Alireza (Edith Cowan University) | Ali, Muhammad (Curtin University, Edith Cowan University) | Iglauer, Stefan (Edith Cowan University)
Nanoparticles (NPs) based techniques have shown great promises in all fields of science and industry. Nanofluid-flooding, as a replacement for water-flooding, has been suggested as an applicable application for enhanced oil recovery (EOR). The subsequent presence of these NPs and its potential aggregations in the porous media; however, can dramatically intensify the complexity of subsequent CO2 storage projects in the depleted hydrocarbon reservoir. Typically, CO2 from major emitters is injected into the low-productivity oil reservoir for storage and incremental oil recovery, as the last EOR stage. In this work, An extensive serious of experiments have been conducted using a high-pressure temperature vessel to apply a wide range of CO2-pressure (0.1 to 20 MPa), temperature (23 to 70 °C), and salinity (0 to 20wt% NaCl) during CO2/water interfacial tension (IFT) measurements. Moreover, to mimic all potential scenarios several nanofluids at different and NPs load were used. IFT of CO2/nanofluid system was measured using the pendant drop method as it is convenient and flexible technique, particularly at the high-pressure and high-temperature condition. Experimentally, a nanofluid droplet is allowed to hang from one end of a dispensing needle with the presence of CO2 at the desired pressure and temperature. Regardless of the effects of CO2-pressure, temperature, and salt concentration on the IFT of the CO2/nanofluid system, NPs have shown a limited effect on IFT reduction. Remarkably, increased NPs concentration (from 0.01 to 0.05 wt%) can noticeably reduce IFT of the CO2-nanofluid system. However, no further reduction in IFT values was noticed when the NPs load was ≥ 0.05 wt%. Salinity, on the other hand, showed a dramatic impact on IFT and also on the ability of NPs to reduce IFT. Results showed that IFT increases with salinity particularly at relatively low pressures (≤ 5 MPa). Moreover, increased salinity can eliminate the effect of NPs on IFT. Interestingly, the initial NP size has no influence on the ability of NPs to reduce IFT. Consequently, the potential nanofluid-flooding processes during EOR have no negative effect on the later CO2-geosequestration projects.
The extraction of geothermal energy, in situ minerals, liquid and gas hydrocarbons, and subsurface water are all constrained by the flow of fluid through fractured media in the earth’s crust, as is the viability of projects involving CO2 sequestration, nuclear and hazardous waste storage, hydrocarbon storage, and subsurface cavities. Subsurface fractures are the main fluid pathways as the matrix permeability is negligible in most rocks. In situ recovery (ISR) or in situ leaching (ISL), particularly in hard rock, poses some challenges currently. One of the main problems is the modelling of fluid flow in fractured rock masses, and this was the primary focus of this project. Modelling fluid flow in fractures can be done in many ways. The modelling showed that ISL in hard rock demonstrates potential. However, the modelling also exhibited the need for advancements in the fluid flow in fractures modelling area. In this paper comprehensive review of developed approaches for subsurface fracture mapping, processing and characterisation to build a fractured rock mass geometry and fluid flow simulation and mineral leachability along with examples were illustrated.
The extraction of geothermal energy, in situ minerals, liquid and gas hydrocarbons, and subsurface water are all constrained by the flow of fluid through fractured media in the earth’s crust, as is the viability of projects involving CO2 sequestration, nuclear and hazardous waste storage, hydrocarbon storage, and subsurface cavities. Also, fluid flow through fractured media affects the health and stability of the subsurface environment, and the populations that live above. Subsurface fractures are the central fluid pathways as the matrix permeability is negligible in most rocks. So, the presence and nature of subsurface fractures play a fundamental role in many human activities.
Mining in future will be more challenging, because of declining ore grades associated with deeper mining and finely disseminated target minerals in heterogeneous ore bodies, as well as complex mineral association with gangue material, often in locations that are difficult or risky to access. In many areas, ore grades declined by almost 50% over the last 30 years, making mineral processing mostly uneconomical for such minerals. Under these circumstances, innovation in in situ recovery could be a suitable alternative to unlocking resources. The idea of in situ recovery first started with solution mining to extract salt, potash or other minerals as shown in Figure 1(a). It was subsequently developed for recovery from porous media such as sedimentary soil and rock or heavily jointed rock masses as illustrated in Figure 1(b). In situ recovery from porous media has become well established during the last few decades, owing to the presence of void spaces and their connectivity, which facilitate fluid flow from injection wells to recovery wells. In situ recovery of target metals from hard rock is challenging, due to a lack of knowledge about fracture conditions, their connectivity and consequently rock mass conductivity and target metal recoverability, as shown in Figure 1(c).
Yu, Hongyan (Northwest University) | Wei, Xiaolong (University of Houston) | Wang, Zhenliang (Northwest University) | Rezaee, Reza (Curtin University) | Zhang, Yihuai (Curtin University) | Lebedev, Maxim (Curtin University) | Iglauer, Stefan (Edith Cowan University)
The gas content in shale reservoir is of great importance in reservoir evaluation. Shale reservoir has various gas including free gas, adsorpted gas and soluted gas. Free gas take an important part for the total gas content. Hence, we investigated three equations for water saturation calculating and compared and improved them based on theoretical analysis in order to find a siutable one for the shale reservoir characterization. The results indicate that the Archie formula has several limitations applied to complex pore structure, which leads to high water saturation. Since the Archie formula was proposed by experimental data in pure sandstone without enough consideration about the clay of shale reservoir. The Waxman-Smits is suitable to shale gas reservoirs through theoretical analysis, but there are several uncertain parameters. The conductivity of formation water is necessary parameter in calculation of formation water saturation, but calculating the conductivity of formation water is difficult in shale gas reservoir because of its intricate characterization of pore structure and conductivity. Waxman-Smits model take account for the clay conductivity, but there are several uncertain parameters which are hard to obtained, resuting high error. For instance, the equivalent conductivity of exchange cations (B) and the capacitance of exchange anions (Qv) can not be defined accurately relied on experimental calculation, which causes indefinite influence on results. Thus, we concluded that selecting the improved Indonesia equation is a better method to calculate water saturation. This study provided a comprehensive analysis and an accurate way for water satruartion evaluation in shale reservoir.
CO2 storage in deep reservoir is an efficient way to mitigate climate change. The carbonate reservoir is one of the selected storage sites but which is sensitive to the acidic environment, where the CO2 saturated formation water could be as medium acid in the reservoir condition and hence change the microstructures. However, the capillary trapping mechanism is highly corrected with such microstructures. Thus, fully understand such CO2-water-rock interaction and the related capillary trapping change are very important for the storage security issues. In this paper, we microCT imaged the microstructure change of oolitic limestone sample due to CO2 saturated brine injection, and calculated the capillary pressure based on the fractal theory. We found that the calculated capillary pressure decreased after live brine flooding which indicated a CO2 capillary trapping loss and such calculated capillary pressure change was also highly corrected with the morphology of the dissolved matrix area.