Miscible CO₂ injection appears to be an important enhanced oil recovery technique for improving sweep efficiency and eliminating CO₂-oil interfacial tension resulting in up to 10% higher oil recovery compared to immiscible flooding, in addition to the environmental benefits of reducing greenhouse gas emissions through carbon capturing utilising and storage (CCUS). Moreover, this technique could be similarly applicable to natural gas and nitrogen projects to increase oil recovery and to reduce the associated gas flaring. However, miscible displacement may not be achievable for all reservoirs, in particular, reservoirs with high temperature where high injection pressure would be needed to reach miscibility which likely exceeds the formation fracture pressure. Therefore, to further achieve reservoirs’ potential, there is a pressing need to explore a viable means to decrease the miscibility pressure, and thus expand the application envelop of miscible gas injection in reservoirs with high temperatures.

In this work, we aim to provide insights into minimum miscibility pressure (MMP) reduction by adding chemicals into CO₂ phase during injection. We achieved this objective by performing a comprehensive review on chemical-assisted MMP reduction using different chemical additives (e.g., alcohols, fatty acids, surfactants) and different experimental methodologies.

Previous experimental studies have shown that a fraction of chemical additives can yield up to 22% of MMP reduction in CO₂-oil system. Based on results analysis, surfactant based chemicals were found to be more efficient compared to alcohol based chemicals in reducing the interfacial tension in the CO₂-oil system. Based on the current experimental results, adding chemicals to improve the miscibility and reduce the MMP in the CO₂-oil system appears to be a promising technique to increase oil recovery while reducing operating cost. Selection of the effective chemical additives may help to expand the application of miscible gas injection to shallow and high temperature reservoirs. Furthermore, our review provides an overall framework to screen potential chemical additives and an injection strategy to be used for miscible displacement in CO₂ and/or gas systems.

The mode-I fracture toughness is of great significance for evaluating the fracturing ability of shale reservoirs. In this study, the mode-I fracture toughness of the shale in the Lower Silurian Longmaxi Formation, Southern Sichuan Basin was determined with the Cracked Chevron Notched Brazilian Disc (CCNBD). Based on the experimental data, the relationships among the mode-I fracture toughness, the density, the acoustic time and the clay mineral content were analyzed. The shale samples for fracture toughness test from cores were commonly limited, the investigation of fracture toughness using well logs was necessary. Therefore, a prediction model was proposed by correlating the fracture toughness with well logs responses. The results indicate that the fracture toughness of shale samples is from 0.4744 MPa·m^1/2 to 1.0607 MPa·m^1/2 with an average of 0.7817 MPa·m^1/2, indicating that the anisotropy of fracture toughness of the Longmaxi Formation shale. The clay mineral content and the density have a positive effect on the fracture toughness, whereas the acoustic time plays a negative role on the fracture toughness. The clay mineral content has an important effect on the relationships among fracture toughness, acoustic time and density. The prediction model can provide continuous data of mode-I fracture toughness along the wellbore for field hydraulic fracturing operation, and it has certain guiding significance in the exploration and development of oil and gas reservoirs

The consequences of sandstone reservoir rock failure may lead to sand production. This phenomenon can have negative impact on lifting cost and economic of any field development. Metal erosion due to sanding can lead to loss of integrity and hydrocarbon leakage. Poor decision on the type of completion can risk the viability of the field. To facilitate best sand management over the life of a field and to maintain economical productivity, accurate prediction of sand production volume/rates is needed to increase both productivity and the ultimate recovery of the hydrocarbon while keeping the operating cost low. This paper summarizes the sand production modeling for onset and volume of sand namely technology that required to improve understanding on sand production and mitigation. Three main questions will be answered, why industry needs to worry about sand production, what are the available technologies to predict sanding volume/rates finally, how the current technologies can be improved to estimate sand production volume/rates.

Accelerating mass exchange between matrix and fractures is the essence of enhanced oil recovery (EOR) in tight formations after natural depletion. Low salinity water (LSW) injection has been commercially-proven in conventional reservoirs EOR, with scale projects in progress worldwide. There is, however, a lack of understanding of the EOR effect in tight formations. Therefore, in this work, we introduced LSW-EOR to a target tight formation using huff-puff mode. Spontaneous imbibition (SI) tests were firstly performed on homogenous Berea sandstone cores with decreasing salinity brine to observe the production response. The results indicated that the oil recovery of the tight rock was boosted by tuning brine salinity. Of all the used brines with salinity ranging from 0.021% to 2.1% TDS (total dissolved salinity), the 0.21% TDS brine showed a rapid increase in oil production over imbibing time, which finally led to an incremental oil recovery of 4.5% OOIP (original oil in place). Core-scale modeling was conducted by history-matching the oil recovery dynamics of the SI results through modifying capillary pressure and relative permeability. A full-scale reservoir model was constructed using micro-seismic data to model fracture geometry combing fracturing results and scaling parameters obtained from core scale history-matching. It is proven that LSW huff-n-puff stimulated the oil production after natural depletion and improved MEE (mass exchange efficiency) of the target formation, but the EOR benefit was not comparable to CO₂ and surfactant-assisted water huff-puff methods.

Understanding the hydraulic and frictional sensitivity of fault to different injection conditions is one of the efficient ways to provide useful implications for fault reactivation potential. Numerical simulations of fractured reservoir have provided information on how fault behaviour varies under changing hydromechanical properties and injection conditions. A coupled hydro-mechanical model which can represent the elastoplastic behaviour of a fault was employed to predict and quantify the effects of varying injection positions and injection rates on permeability response and potential of fault reactivation under isothermal injection. We examine the sensitivity of seismic event magnitude and timing to variations in both pressure perturbation and stress as injection location changes. We generate results for two scenarios: one with changing injection position but with uniform injection rate, and another scenario with increasing injection rate at the same injection position. We observed that the potential of fault reactivation is affected by the hydraulic diffusivity potential of the fluid pressure, and this mechanism is mediated by a function of the injector position and injection rate. As the velocity of fluid transmission increases, increasing fluid pressure impact pore pressure elevation and reduced effective stress. However, an injector position where there is low diffusivity causes low pore pressure build-up rate, incapable of inducing shear failure, and thus, permeability enhancement is retarded in this case. Accordingly, the injection rate variation influences the rate of pore pressure build-up, the timing and magnitude of induced seismic events. This is also reflected in the permeability evolution as a response to the variations in the magnitude of fault openings and cracks. This changing injection conditions however influences the timing required to reach the critical peak friction point as pore pressure build-up rate and sensitivity to loading response change. Hence, with changing position and rate of injection, the evolution of fault permeability appears to be intrinsically controlled by a condition which favours elastoplastic deformation and fracture failure, with slip distance increasing with high injection rates.

When pressure in gas reservoirs fall below the dew point, condensate banking occurs around the wellbore which alters the fluid flow behavior. The state of the knowledge on this flow behavior is yet not fully-developed; which leads to severe problems in field. In this study, the Al-Hussainy, Ramey, and Crawford Solution Technique has been modified to accurately resemble the real gas flow behavior for this condition. First, a primary investigation was conducted to observe the severity of the problem in three condensate banked reservoirs. Then this study involved Constant Composition Expansion tests for determining the dew point, Prode Properties software for modeling the reservoir fluid properties, Flowing Material Balance (or Dynamic P/Z Material Balance) for identifying the pressure distribution of the selected reservoirs. The real field data along with the determined (analytical, computational, and experimental) data were incorporated to check the validity of the models. The modification proposes a Dimensionless Correction Factor (C_D) for any condensate banked reservoir and identifies parameters such as the Perforation Factor (P_f) and Heterogeneity Factor (n). It is found that the Modified Al-Hussainy, Ramey, and Crawford Solution Technique successfully models the actual flow characteristics of the stated condition.

The diffusivity equation is a partial differential equation (PDE) which can be used for fluid flow modeling in porous media. Determining reservoir parameters from pressure data (i.e., pressure transient analysis) is one of the most important steps in the process of field development. This initial evaluation can be used to make decisions about future developments. Wireline Formation Testing (WFT) is one of the most popular techniques for parameter estimation and has received significant attention in recent years. The main problem plaguing WFT is a phenomenon known as the “supercharging effect,” which essentially refers to mud invasion, and this, in turn, alters pressure distribution across the system.

In this study, an analytical solution for fluid flow modeling in spherical coordinates with non-uniform initial pressure is presented. This new procedure takes into account the effect of mud invasion, or, in other words, the supercharging effect. The accuracy of this derivation was validated using previous semi-analytical solutions (the Laplace method) in addition to field data. New type curves and dimensionless parameters, which can be used for pressure transient analysis, are also proposed. This procedure is applied to the WFT data that was obtained from an oil field in the south of Iran, and an excellent agreement (less than 10% error) was observed. In addition, there is considerable uncertainty regarding the radius of investigation for spherical flow. This is important as this parameter greatly affects the applicability of WFT. The analytical derivation of this study was used to determine a reasonable value for this parameter as well.

The pore-scale mechanism of the waterflooding contributes to enhancing oil recovery, which has been widely emphasized in the petroleum industry. In this paper, the performances and accuracy of three tracking interface algorithms, including VOF, LS, and VOSET, are compared and analyzed through two-phase flow in the conceptual model of pore-throat. The results show that the VOSET method combines the advantages of the other two methods, which not only satisfies the mass conservation but also improves the continuity of the physical quantities near the interface. Then, based on the binary image of the pore, the two-dimensional micro pore model is reconstructed by extracting image contour. The grid independence of the reconstructed pore model is verified by the single-phase flow simulation. The waterflooding process in the reconstructed pore model is simulated using the VOSET method, and the effects of displacement speed and wettability on the oil recovery are analyzed. The morphologies of residual oil under different conditions of wettability are investigated and analyzed. The study provides a basic theory for modeling the pore-scale oil-water flow and optimizing the scheme of the water injection.

A highly efficient and environment-friendly scale inhibitor (MA-VA-VS) was synthesized via free radical solution polymerization method, where maleic anhydride (MA), vinyl acetate (VA) and vinyl sulfonate (VS) acted as monomers, while ammonium persulfate was used as initiator. The inhibition performance and the structure as well as properties was characterized using static jar measurement and dynamic test, Fourier transform infrared spectroscopy and thermogravimetric analysis. The surface morphology and composition of scale formed in the solution were examined using scanning electron microscopy and X-ray diffraction, respectively. The binding energies of inhibitor with calcite (104) face were calculated using Materials Studio 2017 (MS) at 323 K.

The results show that the inhibition efficiency gradually increases with increasing inhibitor concentration. While as the Ca²⁺ concentration increases, the efficiency first increases and then decreases. With the increase in temperature or pH, the efficiency generally decreases. It is confirmed that the inhibition efficiency can reach 91.4% when 150 mg/L MA-VA-VS is used in a flow condition. Both the calculated binding energy and inhibition performance evaluation results demonstrate that the scale inhibition performance of MA-VA-VS is better than a commercial scale inhibitor (HPMA). The excellent inhibition performance of this inhibitor is due to its chelation and dispersion properties.

Oil storage in cavern tank is one of the important ways of oil storage. More than 80% of the oil tanks in the cave storage have been used for around 30 years in China and leakage accidents are likely to occur. When it occurs, the motor closing facilities preventing leakage spreading should be set up. The leaking oil flow characteristic in tunnel must be known for setting up the motor closing facilities. Based on the open-channel unsteady flow theory, a numerical model of tank leakage coupling the oil flow in tunnel was developed, and the characteristic line method was used to solve the model under the given initial condition and boundary condition. The variation of the depth and flow rate with time of oil flowing in the tunnel can be obtained. In order to verify the accuracy of model, the measurement data of high accuracy experimental system for unsteady open-channel flow were conducted to compare with the calculation. It fully confirms the high precision of the numerical model and reflects the variation characteristics of each hydraulic parameter in the numerical model of unsteady open channel flow truly. And then, the leaking oil flow characteristic in tunnel was obtained. It is that the farther from the leaking tank, the lower depth and flow rate of the oil in the tunnel revealed. Furthermore, the effect of the size of oil tank crack on the depth and flow rate was investigated. The greater size of crack makes the oil flow rate higher and the oil deeper in the tunnel and flow faster.

This paper presents a decision-making support system for situation risk assessment associated with critical alarms conditions in a gas facility. The system provides a human operator with advice on the confirmation and classification of occurred alarm. The input of the system comprises uncertain and incomplete information. In the light of uncertain and incomplete information, different uncertainties laws have been associated with the probabilistic assessment of the system loops which combine data of several sources to reach the ultimate classification. The implemented model used Observe-Orient-Decide-Act loop (OODA) combined with Bayesian networks. Results show that the system can classify the alarms system.

This paper investigated the failure cause of phantom downlinks of a flow rate detection mechanism in a rotary steerable system and developed a prevention algorithm. Downlinking is the process of controlling a drilling tool from the surface by sending commands to downhole. Directional drillers send downlinks to the rotary steerable system to adjust steering parameters to achieve the desired well plan. The downlink demodulation of downhole tools is achieved through the measurement of flow rate and correlation of waveform with predefined command models; downlink acceptance is based on the correlation rate. One case study revealed that phantom downlinks were due to the variation of turbine rotation speed, which was the result of alternator load changes. A prevention algorithm of conducting a signal energy check was proposed and implemented. The algorithm can successfully prevent phantom downlinks that are usually of low-level energy and only accept authentic downlinks. The work improved the downlinking reliability of the rotary steerable system. This methodology can be further applied to other downlink demodulation mechanisms using collar speed or pressure measurement.