Upstream Oil and Gas Technology最新文献

Hysteresis has a significant role in evaluating hydrocarbon recovery and better understanding fluid flow in porous media. In this paper, a comprehensive review of research on the hysteresis of capillary pressure ($P_c$) and its applications in petroleum engineering are reported. Both theoretical and experimental investigations of hysteresis of $P_c$ is compared and discussed in detail. The review highlights a range of concepts in existing models and experimental processes for hysteresis of $P_c$ in porous media. Furthermore, this paper tracks the current development of hysteresis and provides insight into future research trends. This study also serves to provide an insight into future research opportunities to fill the research gaps on capillary pressure in the system of porous media.

The traditional semi-steady state inflow equation involves Dietz shape factor which depends on reservoir geometry and well location in that geometry. The actual Dietz shape factors are computed utilizing the equation based on the method of images. In this respect, the methodology for the calculation of the Dietz shape factor by means of the method of images is presented. The correlation developed for the estimation of Dietz shape factor is based on the Gaussian function. The correlation is valid for the homogeneous rectangular reservoir areas with aspect ratios in the range from 2 to 5. It is observed that the absolute difference from the actual logarithm of Dietz shape factor is less than 0.16 and 0.43 for the ratio of well coordinates to corresponding block lengths in the range from 0.2 to 0.8 and in the range from 0.15 to 0.85, respectively. The study additionally involves the comparison with the results of the previous simple analytical solution developed for prediction of the Dietz shape factor. The comparison reveals slight improvements in estimation of the Dietz shape factor by means of the developed correlation for well locations close to the borders of the reservoir area.

The Rate of Penetration (ROP) is a vital parameter in drilling operations. Due to the complex relationship between the parameters affecting ROP, accurate prediction of ROP is hard to be obtained analytically. In this study, a recurrent neural network model was developed to estimate ROP using Plastic Viscosity (PV), Mud Weight (MW), flow rate (Q), Yield Point (YP), Revolutions per Minute (RPM), Weight on Bit (WOB), nozzles total flow area (TFA), and Uniaxial Compressive Strength (UCS). The data were collected from more than 2000 wells drilled worldwide. The network architecture was optimized by trial and error. The data were categorized into three sets; 70 % for training, 15 % for validation, and 15% for testing. The created network predicted ROP with an average R² of 0.94. With this tangible prediction method, oil and gas companies can better estimate the time of well delivery as well as optimizing ROP by altering the controllable input parameters affecting the ROP model. Artificial intelligent methods have shown their potential in solving complex problems. The oil and gas industry can benefit from artificial intelligence, especially with the large data sets available, to better optimize the drilling process.

This paper describes a novel strategy to optimize the drilling time of three-dimensional (3D) directional wellbore trajectories using a vector-based approach subject to drilling and geological constraints. Many existing well-path models require manual entry for certain geological constraints such as formation dip or kick-off limit. In contrast, this vector-based approach ensures that geological constraints are automatically satisfied by building a geological model, and extracting a borehole log of key points along the well-path. The presented approach applies and compares a deterministic optimization technique known as Constrained Optimization by Linear Approximation (COBYLA) with a Genetic-Algorithm (GA) global optimization to determine the optimum 3D well path to drill the target. While optimizing the path, the model determines the optimum kick-off point based on the subsurface-formation strength and depth subject to predetermined doglog severity, inclination and azimuth angles. The methodology is applied to well paths with different number of build-up and drop sections in unconstrained and constrained geological settings. Results show that COBYLA and GA are comparable when not using geological modelling while GA is superior for complex well-path geology-assisted optimization problems. The technique is applicable for a single well path planning, and can be expanded to a set of wells being optimized during Field Development Planning (FDP).

Most important aspect of drilling clay-rich formations is preventing the hydration and dispersion. Oil based drilling muds (OBM) have historically been the first choice for drilling these kinds of formations, however the usage of the OBM is currently forbidden in drilling operation due to environmental issues. As an alternative, many inhibitive water-based muds were proposed. This paper describes the experimental work carried out on ten shale samples to evaluate stabilization of shale and clay-fluid interactions. After mineralogical analysis of shale samples, swelling and hot-rolling dispersion test were conducted using fresh water, polyamine, sodium silicate and oil base mud. Mineralogical analysis results showed that the cutting samples of 3, 4, 5, 6 and 7 have the highest clay content. Cation exchange capacity (CEC) results indicated that the shale sample with high concentration of smectite recorded the highest CEC value as it has the ability to absorb water into its inter-layers and exchange cations. When shale samples were tested in linear Swell meter, it is expressed the lower swelling percentage for oil base mud and maximum for fresh water. However, it was found out that both sodium silicate and polyamine mud systems yield the same performances. Furthermore, dispersion results showed that the shale recovery percentage increased from 16.3% to 56.2% when sodium silicate mud was used instead of polyamine mud. For the fresh water and oil base mud, results confirmed findings of linear swelling meter test, which is the lowest recovery for the fresh water (6.7%), and maximum recovery for the OBM (109.9%). The improved swelling inhibition suggested that sodium silicate mud could be effectively used to control wellbore instability while drilling through the Kolosh Formation .

The wellbore instability costs the drilling of oil and gas wells billions of dollars, yearly. This might happen when the strength and resistance of the surrounded rock become exceeded by local stresses around the borehole. In order to keep the borehole stable, an appropriate density for the drilling mud must be determined based on the rock failure analysis which includes the identification of the rock strength, selection of the constitutive model, and chosen the accurate rock failure criterion. In this study, we used the nonlinear forms of Mogi Failure Criterion and Polyaxial Test Data to estimate the collapse and fracture pressures required to stabilize the wellbore in different well trajectories and in-situ stress regimes. The results reveal that in various in-situ stress regimes, the inclination and azimuth of the borehole have an important role in wellbore stability during drilling operation. It was identified that the Extended Mogi-Coulomb (EMC) and Mogi-Coulomb (MC) parameters in Well A (EMC = 257 psi and MC = 374 psi) are higher compared with Well B (EMC = 0.84 psi and MC = 0.54 psi). Also, the field case studies indicate that the nonlinear forms of Mogi Failure Criterion are greatly close to the real mud weight used to successfully drill the borehole in the field. This kind of borehole stability analysis plays a significant role in designing the drilling plan for oil and gas wells in order to minimize and eliminate the instability problems.

Recently, a light oil from different formations is added to the existing crude oil stabilization plant to associate the production of crude which unfortunately not enough to release off all light components and as a results the true vapor pressure (TVP) exceeds the desired specification of 82737.1 Pa/12 psia for the exported oil. The Simulation results were comparable with industrial data to give a good match between the Aspen Hysys results and the industrial analysis. The existing plant operates in three stages of gas/liquid separators where it is reported that changing production conditions, such as inlet temperature, dry fluid flow rate, water flow rate and the temperature of the outlet fluid from Fired Heater, do not make the value of TVP within the permissible limits of (68947.6–82737.1) Pa / (10–12) psia. The current work studied the effect of adding a fourth vessel on the production specifications, where it shows a successful results on decreasing the TVP. It was found that, the live crude was successfully stabilized to a TVP of less than 12 psia / 82737.1 Pa when the feed dry fluid flow rate (26.4–105.6) kbd and the minimum base sediment and water cut in the feed stream is 4 Vol%. It is also found that, the temperature of fluid has a significant impact on the crude oil specifications where the inlet fluid temperature should be in range of (43–51.5) ⁰C and the differential temperature across the Fired Heater in range of (16–24) ⁰C with feed temperature range (40–55) ⁰C.

The innovative lightweight slurry 85 lb/ft3 (pounds per cubic foot) was prepared using three blended materials with a combination of 20% micro silica, 44% cenosphere and class-g cement, a special hydraulic binding material to forms strong bonding energy due to a combination of moderate sulphate-resistant and high sulphate-resistant. Cementing laboratory tests were carried out in the mix with this blended cement and some additives to control fluid loss increase the bonding energy and delay the cement setting time. After added this blended cement, the mechanism of the slurry was optimized the particle size distribution to maximum solids content, less water wasted in the void, the solid volume fraction increased to 50.2%. The blended composition shows fine nature and high reactivity as a pozzolanic material to improve slurry stability. Also, concluded that the high solid content increased in the slurry to enhance comprehensive strength, mechanical durability, permeability and required thickening time for low-density 85 pcf lead slurry. Pilot test results presented good compressive strength and thickening time at low temperatures.

The research study aimed to investigate the effect of coupled metakaolin and nano-silica (nano-SiO₂) on improving the compressive and shear bond strengths of class G oil well cement. Samples curing was done at 80 °C for 3, 7, 14, and 28 days. XRD and TG-DSC techniques were used for cement phase characterization. The results indicated that the cement system with 2% nano-SiO₂ and 20% metakaolin increased the compressive strength by 20.0 and 21.4%, and shear bond strength by 205.5 and 90.8% for 3 and 28 days, respectively. This means the synergistic effect is more significant for cement-formation bond strength development. The results of this study, therefore, points to a potential ternary cement system for durable oil wells.

Mucuna solannie is a Papilionaceace used in culinary. Its rheology using API specifications was evaluated. Compared with Carbogel,  plastic viscosity of 17 against 16cP at 8ppb, yield point of 27 against 26 lb/100ft² at 2ppb, 10 minutes gel strength of 17 against 15 lb/100ft² at 6ppb, annular flow index of 0.46 against 0.42 at 8ppb, annular consistency index of 44.6 against 30.6 eq-centipoise at 2ppb, pressure drops of 10.43psi against 8.60psi at 2ppb, and cutting concentration of 1.272 vol. % against 1.215 vol. % at 8ppb were obtained. The results showed it has nano- particles