Da, Chang (The University of Texas at Austin) | Elhag, Armo (Khalifa University of Science and Technology) | Jian, Guoqing (Rice University) | Zhang, Leilei (Rice University) | Alzobaidi, Shehab (The University of Texas at Austin) | Zhang, Xuan (China University of Petroleum) | Al Sumaiti, Ali (Khalifa University of Science and Technology) | Biswal, Sibani (Rice University) | Hirasaki, George (Rice University) | Johnston, Keith (The University of Texas at Austin)
Stabilization of CO2 in water (C/W) foams with surfactants at high temperatures and high salinities is challenging, due to limited solubility of surfactants in aqueous phase, foamability and thermal stability. The apparent viscosities of C/W foams has been raised to up to 35 cP with viscoelastic aqueous phases formed with a diamine surfactant, C16-18N(CH3)C3N(CH3)2 (Duomeen TTM), or a zwitterionic surfactant, cetyl betaine, at 120 °C in 22% total-dissolved-solids (TDS) brine. Duomeen TTM is switchable from the nonionic (unprotonated amine) state, where it is soluble in CO2, to the cationic (protonated amine) state in an aqueous phase under pH ~6. Therefore, it may be injected in either the aqueous phase or the CO2 phase. The formation of viscoelastic phases with both surfactants lowers the minimum pressure gradient (MPG), and strengthens the lamella against drainage and Ostwald ripening by making the external aqueous phase more viscous, leading to stable foam even at very high foam quality. Both surfactants were shown to have excellent thermal stability and to form unstable emulsions when mixed with oil (dodecane). The core flood results showed that strong foam could be easily generated with both surfactants at a superficial velocity of 4 ft/day. The oil/water (O/W) partition coefficient of Duomeen TTM was very sensitive to pH, while that of cetyl betaine was constant over a wide range of pH. The ability to stabilize C/W foams at high temperature and salinity conditions with a single thermally stable surfactant is of great benefit to a wide range of applications including EOR, CO2 sequestration and hydraulic fracturing.
Waterflooding in low permeability, fractured and oil-wet carbonate reservoirs yields extremely low oil recovery due to bypassing through fractures and little imbibition into the matrix resulting in a large amount of oil remaining in the reservoir. Gravity-aided gas injection is studied at the lab-scale in this work to enhance oil recovery from fractured reservoirs. The miscibility of the gas with a model oil (decane with naphthenic acid) is varied by enriching the methane with ethane. Mobility of the gas is decreased by incorporating the gas in foam or glycerol-alternating-gas floods. As the miscibility increases, the oil recovery increases, but reaches a plateau above the near-miscible conditions. The foam flood improves oil recovery by diverting gas into the matrix, if the gas is sufficiently soluble in the oil and the gas-oil capillary pressure is sufficiently low. The pressure gradient generated in the fracture by foam helps in the diversion of the gas into the matrix. Glycerol-alternating-gas floods result in minor additional oil recovery over foam floods because the pressure gradients are about the same. These experiments need to be repeated after gas floods (before conducting foam floods). Near-miscible (and miscible) foam floods increased the oil recovery to high values (about 85% OOIP) in core floods and their scale-up to reservoir scale warrants further study.
Oil recovery during waterflooding of carbonate reservoirs is often low due to their oil-wetness and heterogeneity. Surfactant-Polymer (SP) flooding can improve the oil recovery from these reservoirs through ultra-low interfacial tension (IFT), mobility control and wettability alteration. However, there are several challenges associated with this process in high salinity and high temperature carbonate reservoirs related to thermal stability of polymers at elevated temperatures, compatibility of surfactants with high concentration of divalent cations present in formation brines, and geochemical interactions with carbonate minerals. This paper addresses the following challenges: surfactant interaction with formation brine containing high concentration of divalent cations and thermal stability and transport of polymers in carbonate rocks at a high temperature (80 C). Surfactant phase behavior experiments were performed to identify promising surfactant candidates which showed ultralow IFT with crude oil and aqueous stability at high temperature in high salinity and high hardness brines. A systematic study was performed to understand the effect of surfactant hydrophobe length on phase behavior, oil recovery, and surfactant retention in coreflood experiments. Novel surfactants with very short hydrophobes and cosolvent-like properties were also included to further optimize the phase behavior. Surfactants of larger hydrophobe length, containing similar number of EO and PO groups, gave higher solubilization ratio (and lower IFT) and lower optimum salinity. Specialty synthetic polymers with good thermal stability and salinity tolerance (TDS > 90,000 ppm) were investigated for their transport in single-phase corefloods. Results showed successful transport of polymer, without degradation in-situ, and improvement in mobility control. SP core floods were conducted using selected formulations in Indiana limestone cores. Coreflood experiments showed small increases in oil recovery over waterflood after the injection of the chemical formulation. Succesful polymer transport was observed in SP corefloods at high temperature.
Newgord, Chelsea (The University of Texas at Austin) | Tandon, Saurabh (The University of Texas at Austin) | Rostami, Ameneh (The University of Texas at Austin) | Heidari, Zoya (The University of Texas at Austin)
Nuclear Magnetic Resonance (NMR) measurements have been attractive options for fast wettability characterization of rocks in petroleum reservoirs. Several NMR-based wettability indices are documented in previous publications. These methods often require calibration at irreducible water and residual hydrocarbon saturations, which complicates their applicability in mixed-wet rocks at different fluid saturations. We recently analytically derived a new NMR-based wettability index and confirmed its reliability using pore-scale NMR simulations. This new model only requires calibration at fully water- and hydrocarbon-saturated states for different wettability states ranging from water-wet to hydrocarbon-wet. In this paper, we experimentally quantify the influence of wettability on NMR measurements and verify the reliability of the new NMR-based wettability model in the core-scale domain for partially-saturated rocks.
First, we measured the transverse relaxation (
We measured the wettability of the core samples to be in the range of −0.6 to 0.5 on the Amott-Harvey index. The calculated NMR-based wettability for the altered core samples were in the range of −0.66 to 0.51, which was in good agreement with the wettability estimates from the Amott-Harvey method. The experimental results demonstrated that our new NMR-based wettability model successfully estimates the wettability of mixed-wet rocks in a wide range of wettability and eliminates the need for calibration at irreducible water and residual hydrocarbon saturations. The outcomes can be used to improve the speed and reliability of NMR-based wettability characterization. The results from these core-scale measurements are promising for application of the introduced model to log- and field-scale wettability assessment in mixed-wet rocks with complex pore-structure and at different fluid saturations.
The integrity of a geological formation is a primary concern in any underground fluid injection project. Hydraulic pressurization due to injection may reduce fault strength, trigger fault slippage, and cause fault reactivation. The reactivated fault affects the fluid migration and loss from the injection zone, which might undermine the efficiency and safety of the project. Hence, a reliable modeling of fault reactivation is critical.
In this work, we propose a new approach to modeling fault reactivation. Faults are complex structures and generally consist of core and damage zones with macroscopic fracture networks. The embedded discrete fracture model (EDFM) is an effective method for simulating complex geometries such as fracture networks and nonplanar hydraulic fractures. We used the EDFM in conjunction with a compositional reservoir simulator to model fault reactivation under hydraulic pressurization. The phase behavior and fluid flow are accurately modeled using the equation of state (EOS) compositional simulation.
The activation of fault occurs at a threshold pressure, which depends on the chemo-mechanical properties of the formation rock. The threshold pressure can be estimated using analytical, numerical, or laboratory methods. In this study, we provided an analytical calculation of the threshold pressure. Moreover, we used a refined, multiphase, compositional, and geomechanical reservoir simulator to predict the threshold pressure. The coupled geomechanical reservoir simulation is computationally expensive; therefore, we suggest using this approach, in the absence of laboratory measurements, to simulate only a few regions of the formation with distinctive rock types. The estimated values of threshold pressures for different geomechanical rock types can be used in our simulations.
We performed large-scale reservoir simulations using the EDFM to investigate the storage capacity of carbon depositional formations representative of the Gulf of Mexico and monitor CO2 migration paths before and after fault reactivation. The results of this study are helpful to evaluate the capacity and integrity of carbon storage sites. Our methodology gives promising results for the prediction of fault reactivation and CO2 migration within a formation.
The proposed approach accurately models faults and their reactivation. It does not require refinement and geomechanical calculation for each gridblock in the domain, which reduces the computational time by at least five times. The significance of this approach becomes more pronounced in large formations with multiple rock types and faults. Although we used our approach for the study of carbon storage, the same methodology can be used for other types of fluid injection, such as water disposal.
Most carbonate reservoirs have fractures which have a detrimental effect on sweep efficiency during oil recovery. The objective of this research is to block the big fractures with polymeric particles and divert the injection fluid into the matrix for better sweep efficiency during CO2 floods. Polymeric particles have been developed that swell as salinity is increased. These particles are termed SISPP or salinity induced swelling polymeric particles. SISPPs swell more in higher concentration brine contrary to common polymeric particle gels (PPGs) which shrink. Water flood and miscible floods are conducted in fractured cores with SISPP placed in the fractures. The SISPP placement increases oil recovery in fractured cores during high salinity water floods and miscible/CO2 floods. Furthermore, a model for particle swelling, and the concomitant change in permeability, as a function of brine salinity was implemented in UTCHEM, and single phase and oil recovery corefloods were modeled. UTCHEM simulations showed good agreement with the experimental results.
The objective of the study is to determine the main mechanisms for sand production and to propose completion designs to minimize sand production for HPHT gas wells in the Tarim Basin. Sand production has been a very serious concern in these HTHP gas wells. This paper presents field results for several key wells which are prone to sanding and investigates the possible reasons and mechanisms responsible for sand production. A fully coupled 3D, poro-elasto-plastic sand production model has been developed and applied to study sand production issues for these wells. Sand production data from several wells were analyzed to better understand the conditions under which sand production occurs and conditions under which it is mitigated.
The sand production model was used to model the different completion designs and flow back strategies that were used in the field. The model couples multi-phase fluid flow and elasto-plasticity to simulate pressure transient and rock deformation during production. The sanding criterion is a combination of both mechanical failure (shear/tensile/compressive failure) and fluid erosion. A novel cell removal algorithm has been implemented to predict the dynamic (time dependent) sand production process. In addition, the complex geometry of the wells and perforations are explicitly modeled to show cavity propagation around hole/perforations during sand production.
For this study, triaxial tests on core samples have been conducted and the stress-strain curves under different confining stresses are analyzed to obtain rock properties for both the pre-yield and post-yield period. The wells were categorized into ones that had massive sand production and ones that showed much less sand production. Operational and mechanical factors that were empirically found to result in sand production were identified. The sand production model was run to verify the role played by different factors. It is shown that completion design, rock strength and post failure behavior of the rock are key factors responsible for the observed sanding in these wells. In addition, the drawdown strategy and the associated BHP change and the extent of depletion play an important role in the sanding rate. Several strategies for minimizing sand production are suggested for these wells. These include, drawdown management, completion and perforation design. In this study, we quantitatively show for the first time that data from HPHT gas wells that suffer severe sand production problems can be modeled and analyzed quantitatively to determine the mechanisms of sand production. This allows us to make operational recommendations to minimize sanding risk in these wells.
Natural fractures are a crucial factor in determining fracture and well spacing in horizontal wells. Their attributes affect the created fracture network and thereby the well producivity and EUR. However, information about the properties of natural fractures is seldom available. In this study, we used a detailed core description from the Hydraulic Fracture Test Site (HFTS), funded by the DOE and an industry consortium, to obtain in-situ natural fracture distribution data. The data was used as input into a hydraulic fracturing simulator to model fracture growth in the presence of natural fractures. The results obtained were then compared with field observations of cores taken from a slant infill well drilled into the hydraulically fractured rock.
The core taken from the slant well located adjacent to the hydraulically fractured well is used to characterize the natural fractures (density and orientation). A two-dimensional discrete fracture network (DFN) is generated based on the core description. Nine coring operations are simulated on the created DFN to generate synthetic core descriptions. Attributes (length and density) of natural fractures are calibrated to match the results obtained from simulated coring operations with real core data. Multi-stage hydraulic fracturing simulations are performed using the calibrated DFN, and the results are presented in this paper.
The core analysis identified three different types of fractures: hydraulic fractures, intact natural fractures, and natural fractures activated by hydraulic fractures. The density and orientations obtained from the core description provide valuable insights on the complex fracture growth behavior. The number of created fractures (propped and unpropped) far exceeds the number of perforations. This indicates the formation of complex fracture networks likely caused by the interaction of the hydraulic fracture with natural fractures and bed boundaries during propagation. A heel-side bias of fluid and proppant distribution within a stage was also observed. The effect of inter-stage stress shadowing on fracture growth could also be inferred.
Excessive cuttings and cavings accumulation due to poor hole cleaning and borehole instability can cause costly stuck pipe incidents. Currently, there is no surface instrument to monitor cuttings volume and detect cavings in real-time. An automated 3D real-time computer vision monitoring system can quantify cuttings return volume, detect cavings presence, and analyze cavings shape. This makes pro-active prevention and mitigation of non-productive time (NPT) caused by poor hole cleaning and wellbore instability possible.
In this paper, we present a real-time computer vision system to measure cuttings properties and detect cavings. The proposed design consists of a 2D high-resolution camera and a 3D profile laser scanner, which collect point cloud/depth data of cuttings/cavings after passing the shale shaker. We apply cutting-edge computer vision algorithms and feature recognition techniques to quantify cuttings volume, detect cavings, and characterize cavings shape. The angularity, flatness, and other geometrical features of cuttings/cavings can be determined from the point cloud 3D data.
A prototype computer vision system was constructed and tested in the lab and test yard to evaluate the system capability to measure cuttings/cavings properties. In a controlled laboratory environment, a sensing algorithm was designed and tested in the presence of drilling fluid. To improve measurement accuracy, both artificial and field cavings were used to simulate realistic scenarios and train a data pool. The system was then validated in a test yard shale shaker testing facility. The accuracy, repeatability, and robustness of the sensors were evaluated against external lighting variances, dust, humidity, etc. The proposed automated cuttings/cavings monitoring system can identify cavings and analyze shape characteristics. By diagnosing potential hazards, the system warns the driller on adverse wellbore conditions and the likelihood of stuck pipe events. This paper proposes and demonstrates a novel 3D depth-sensing system to measure cuttings volume, identify abnormal cavings, and analyze shape. This state-of-art, non-intrusive system evaluates cuttings/cavings quantitatively and delivers algorithms that automate downhole condition monitoring to reduce drilling-related NPT in the field.
Pressure transient testing is a method to obtain information on reservoir characteristics. Thin shale layers isolating productive intervals in a reservoir have important implications for reservoir development and EOR strategies. In addition, weaknesses in caprocks overlying injection intervals may adversely affect the safety of fluid injection approaches including gas storage, waste water disposal, and CO2 geological storage. Even low permeability of a caprock overlying the injection zone can be very important by allowing for pressure dissipation out of the reservoir. In this work, we apply harmonic pressure testing method to characterize a caprock overlying a given injection zone. The diffusivity equations are written and solved in frequency domain for system of injection layer and above zone with the low permeability caprock in between. A vertical well is perforated in the middle of the injection layer. A periodic flow rate pulse is disseminated from the injection well. The pressure pulses traveled through the caprock are observed in the above zone. The hydraulic characteristics of the low permeability caprock are estimated applying the analytical solution based on the above zone pressure amplitude. The caprock diffusivity is found to be in acceptable agreement with the true value. It is shown that the harmonic pulse testing is useful to characterize the intra/inter reservoir low permeability layers (caprocks).