ALBERT

Description: The main aim of the article is to evaluate the gas potentiality for the post-Messinian megasequence in TAO Field, North Sinai Concession, offshore Nile Delta Basin. The detailed petrophysical analysis for three deviated wells in the study area (Tao-3 ST1 Well, Tao-5 STA Well and Tao-7 Well) revealed that the Pliocene Kafr El-Sheikh Formation includes eleven gas-bearing zones. These zones were named: A, B, C in Tao-3 ST1 Well and D, E, F in Tao-5 STA Well. In Tao-7 Well, the interesting zones are named G, H, I, J and K. All of these sandy intervals are relatively shallow in depth and differ in thickness between 4 and 56 m. These zones are characterized by shale volume (10%), total porosity (30–40%), effective porosity (30–35%), gas saturation (50–90%), high effective permeability to gas and low permeability to water. The seismic data displayed that listric faults and the associated rollover folds have an important role in forming structural traps for the examined gas-bearing zones in Tao Field and its surroundings. This work revealed that the success rate in discovering new gas prospects within the Pliocene–Pleistocene succession at North Sinai Concession is very high.

Description: Water injection is an effective method for developing low permeability sandstone reservoirs. In the process of water flooding, reservoir damage can occur due to clay mineral content changes and it will significantly affect oil production. There are few investigations on the changes in clay mineral content and the degree of reservoir damage after injecting the water into low permeability sandstone reservoirs with different permeabilities and lithologies. In this study, low permeability natural cores from different lithological strata were collected from 4 wells in the Daqing sandstone reservoir, and clay mineral components and contents were measured through X-ray diffraction. Changes in the clay mineral content were determined after water injection. The reservoir damage mechanism by clay mineral migration was determined by analyzing scanning electron microscopy (SEM) images after water injection. Meanwhile, the porosity and permeability of the cores were tested after water injection, and the degree of reservoir damage in different lithological strata was determined. The clay mineral content ranges from 6.78 to 14.14% in low permeability sandstone cores and declines by 49.73% after water flooding. Illite, chlorite and illite/smectite mostly decrease, and kaolinite decreases the least. Due to the large particle size of kaolinite, kaolinite migration will block the pore-throats and cause formation damage after water flooding. In argillaceous siltstone and siltstone, kaolinite particles blocking pore-throats are very serious, and the permeability decreases greatly by 21.87–36.89% after water injection. With increasing permeability, the permeability decreases greatly after water injection. The findings of this study can help to better understand the mechanisms of formation damage after injecting water into low permeability sandstone reservoirs.

Description: Availability of gases at the field level makes attractive to water-alternating-gas (WAG) process for low viscosity and light oils carbonate reservoir. However, impact of reservoir heterogeneity on WAG performance is crucial before field application. In general, ramp carbonates have heterogeneity due to variation of permeability and porosity. However, WAG performance significantly affected by permeability variations. This article investigates merits and demerits of WAG displacement due to permeability heterogeneities such as permeability anisotropy, high permeability streaks (HKS), matrix permeability, dolomite and thin dense stylolite layers. High-resolution compositional simulations with tuned equation of state (EoS) were carried out using 2D and 3D sector models. The study focuses on WAG performance in terms of oil recovery, vertical sweep, solvent utilization, gas oil ratio (GOR), water cut (WCT), WAG response time, gravity override, hysteresis, un-contacted oil saturation and economics. The results of simulation show that the heterogeneous reservoir provides initially faster WAG response, lower expected ultimate recovery (EUR), faster gas breakthrough, higher GOR and WCT production compared to homogeneous reservoir. The gas gravity override at smaller wells spacing is less in homogeneous reservoir as compared to heterogeneous reservoir, but it is reverse in case of larger well spacing. In heterogeneous reservoir, the HKS shows significant gas override resulting in poor vertical sweep due to capillary holding, and the high permeability dolomite layer shows early water breakthrough. This reservoir has higher solvent utilization in initial stage, and then, it becomes nearly equal to homogeneous reservoir. Simulation in both reservoirs overestimates incremental recovery of 2–3% OOIP at one pore volume injection because of not involving un-contacted oil saturation as predicted in core flood. The findings of this study will help to understand WAG performance and design in highly heterogeneous reservoirs for field applications. Graphical abstract

Description: The current commercial technologies used to produce heavy oils and bitumen are carbon-, energy-, and wastewater-intensive. These make them to be out of line with the global efforts of decarbonisation. Alternative processes such as the toe-to-heel air injection (THAI) that works as an in situ combustion process that uses horizontal producer well to recover partially upgraded oil from heavy oils and bitumen reservoirs are needed. However, THAI is yet to be technically and economically well proven despite pilot and semi-commercial operations. Some studies concluded using field data that THAI is a low-oil-production-rate process. However, no study has thoroughly investigated the simultaneous effects of start-up methods and wells configuration on both the short and long terms stability, sustainability, and profitability of the process. Using THAI validated model, three models having a horizontal producer well arranged in staggered line drive with the injector wells are simulated using CMG STARS. Model A has two vertical injectors via which steam was used for pre-ignition heating, and models B and C each has a horizontal injector via which electrical heater and steam were respectively used for pre-ignition heating. It is found that during start-up, ultimately, steam injection instead of electrical heating should be used for the pre-ignition heating. Clearly, it is shown that model A has higher oil production rates after the increase in air flux and also has a higher cumulative oil recovery of 2350 cm3 which is greater than those of models B and C by 9.6% and 4.3% respectively. Thus, it can be concluded that for long-term projects, model A settings and wells configuration should be used. Although it is now discovered that the peak temperature cannot in all settings tell how healthy a combustion front is, it has revealed that model A does indeed have far more stable, safer, and efficient combustion front burning quality and propagation due to the maintenance of very high peak temperatures of mostly greater than 600 °C and very low concentrations of produced oxygen of lower than 0.4 mol% compared to up to 2.75 mol% in model C and 1 mol% in model B. Conclusively, since drilling of, and achieving uniform air distribution in horizontal injector (HI) well in actual field reservoir are costly and impracticable at the moment, and that electrical heating will require unphysically long time before mobilised fluids reach the HP well as heat transfer is mainly by conduction, these findings have shown decisively that the easy-and-cheaper-to-drill two vertical injector wells configured in a staggered line drive pattern with the horizontal producer should be used, and steam is thus to be used for pre-ignition heating.

Description: Horizontal well productivity (Jh) equation at pseudo-steady state (PSS) of Mutalik et al. (in: Presented at SPE 63rd annual technical conference and exhibition, Houston, Texas, 1988) has long and widely been known to estimate well performance. One key parameter of that equation is the so-called shape factor (CA) that characterizes the effect of the pressure transient behavior at PSS depending on well and reservoir configuration. For limited well and reservoir configurations, CA tables had been generated decades ago, but at unknown accuracy they are still used widely via tedious correlation or interpolation from those reported CA tables to estimate Jh for different configurations even today. The innovation points in this study are as follows: (1) The pressure transient model of Mutalik et al. (in: Presented at SPE 63rd annual technical conference and exhibition, Houston, Texas, 1988) (PTM) is improved to generalized pressure transient model (GPTM) and verified by converting several dimensional parameters to dimensionless forms. (2) An efficient algorithm is developed, and accurate CA and Jh are obtained for any well and reservoir configuration. (3) The accuracy of the reported CA tables is quantified, and the consequences are determined when they are used to estimate Jh. (4) New CA tables and their correspondence dimensionless time based on drainage area at PSS ((TDA)PSS) tables are generated for a wider range of well and reservoir configurations. Although horizontal wells usually have been drilled with high dimensionless well length (LD) industrially (i.e., LD 〉 10), it is still a significant error in Jh by (

Description: Recently, nanoparticle additives have been used to improve stability and hence efficiency of chemicals during enhanced oil recovery. Herein, a comparative analysis of the application of nanoparticle-stabilized xanthan gum for oil recovery applications was investigated. The nanoparticles used as additives are silicon oxide (SiO2), metallic aluminium oxide (Al2O3), and titanium oxide (TiO2). Rheological measurements were carried out to examine the shear viscosity of the polymeric nanofluids under a range of salinity typical of reservoir conditions. Interfacial tension (IFT) experiment was conducted using Kruss tensiometer. Oil displacement studies were carried out to examine the incremental recovery factor of the polymeric nanofluids. The polymeric nanofluids exhibited better rheological behaviour compared to bare xanthan gum (XG) polymer. At 0.5 wt.% nanoparticle concentration, 0.5 wt.% polymer concentration, shearing rate of 10 s−1, and 3 wt.% NaCl concentration, rheology result shows that the shear viscosity of SiO2-XG, Al2O3-XG, and TiO2-XG is 423 mPa.s, 299 mPa.s, and 293 mPa.s, respectively. Moreover, the polymeric nanofluids lowered the IFT of the oil/brine interface due to adsorption at the nanoparticles at the interface. Finally, oil displacement result confirms that the incremental oil recovery after water flooding by Al2O3-XG, TiO2-XG, and SiO2-XG is 28.4%, 27.6%, and 25.2%, respectively.

Description: Shales are mostly unexploited energy resources. However, the extraction and production of their hydrocarbons require innovative methods. Applications involving carbon dioxide in shales could combine its potential use in oil recovery with its storage in view of its impact on global climate. The success of these approaches highly depends on various mechanisms taking place in the rock pores simultaneously. In this work, properties governing these mechanisms are presented at technically relevant conditions. The pendant and sessile drop methods are utilized to measure interfacial tension and wettability, respectively. The gravimetric method is used to quantify CO2 adsorption capacity of shale and gas adsorption kinetics is evaluated to determine diffusion coefficients. It is found that interfacial properties are strongly affected by the operating pressure. The oil-CO2 interfacial tension shows a decrease from approx. 21 mN/m at 0.1 MPa to around 3 mN/m at 20 MPa. A similar trend is observed in brine-CO2 systems. The diffusion coefficient is observed to slightly increase with pressure at supercritical conditions. Finally, the contact angle is found to be directly related to the gas adsorption at the rock surface: Up to 3.8 wt% of CO2 is adsorbed on the shale surface at 20 MPa and 60 °C where a maximum in contact angle is also found. To the best of the author’s knowledge, the affinity of calcite-rich surfaces toward CO2 adsorption is linked experimentally to the wetting behavior for the first time. The results are discussed in terms of CO2 storage scenarios occurring optimally at 20 MPa.

Description: In recent years, polymeric additives have received considerable attention as a wax control approach to enhance the flowability of waxy crude oil. Furthermore, the satisfactory model for predicting maximum yield in free radical polymerisation has been challenging due to the complexity and rigours of classic kinetic models. This study investigated the influence of operating parameters on a novel synthesised polymer used as a wax deposition inhibitor in a crude oil pipeline. Response surface methodology (RSM) was used to develop a polynomial regression model and investigate the effect of reaction temperature, reaction time, and initiator concentration on the polymerisation yield of behenyl acrylate-co-stearyl methacrylate-co-maleic anhydride (BA-co-SMA-co-MA) polymer by using central composite design (CCD) approach. The modelled optimisation conditions were reaction time of 8.1 h, reaction temperature of 102 °C, and initiator concentration of 1.57 wt%, with the corresponding yield of 93.75%. The regression model analysis (ANOVA) detected an R2 value of 0.9696, indicating that the model can clarify 96.96% of the variation in data variation and does not clarify only 3% of the total differences. Three experimental validation runs were carried out using the optimal conditions, and the highest average yield is 93.20%. An error of about 0.55% was observed compared with the expected value. Therefore, the proposed model is reliable and can predict yield response accurately. Furthermore, the regression model is highly significant, indicating a strong agreement between the expected and experimental values of BA-co-SMA-co-MA yield. Consequently, this study’s findings can help provide a robust model for predicting maximum polymerisation yield to reduce the cost and processing time associated with the polymerisation process.

Description: In large-scale multi-section hydraulic fracturing, the stress environment of wellbore is extreme complex, often causing the unbalanced stress distribution around the wellbore. That poses great challenges to the integrity of the sheath. In this paper, firstly, triaxial compression test and triaxial cyclic test are carried out at 130 °C to study the deformation characteristics of the cement under high temperature. Then based on that, an appropriate plastic mechanics model is established. Finally, the shakedown theory is applied to analyze the model and acquires a maximum cyclic loading under asymmetric stress. The result shows that (1) the well cement, with the increase of load, shows the plastic flow characteristics and can be regarded as an ideal elastic–plastic material under high temperature. (2) During the cyclic loading and unloading process, the "hysteresis loop" becomes denser, which indicates that the accumulation rate of plastic deformation is continuously declining. The main plastic strain appears in the phase of the first loading. (3) The external pressure Pz plays a positive role in the deformation control of the sheath. With the growth of Pz, the maximum cyclic loading Pmax will also increase. (4) Asymmetric stress distribution can significantly affect the bearing capacity of the sheath. If stress difference coefficient λ = 0.3, the Pmax tends to decrease nearly by 50%. With the growth of λ, the negative influence of stress asymmetry reduces gradually. High external pressure is beneficial to reduce the negative impact of the asymmetry. With the growth of λ, the benefit tends to enhance. (5) In engineering practice, if the geology around wellhole showcases the strong asymmetry (the value of λ is large), some steps need to be adopted to reduce the stress concentration.

Description: Given the complexities of reservoir exploration and development, it is vital to understand the geomechanical properties of the reservoir and well in the drilling operation. In constructing a mechanical model of the earth, a combination of environmental geomechanical parameters, as well as the magnitude and direction of stresses, is used. In this study, stress analysis and its effect on azimuth well in deviated drilling in an oil field located in southwestern Iran are investigated. Necessary geomechanical parameters are estimated using density and slowness logs of sonic waves (shear and compression). The Mohr–Coulomb failure criterion is followed to determine a safe mud weight window. A mechanical model of the earth is designed using laboratory data and well logging, and it is validated by the results obtained from laboratory rock mechanics using the calibrated core samples. The results show that drilling in the azimuth at about 135° with an angle of about 15° is the most stable path for the well in the carbonate reservoir formation in the studied oil field.