Petroleum最新文献

A major cause of some of serious issues encountered in a drilling project, including wellbore instability, formation damage, and drilling string stuck – which are known to increase non-productive time (NPT) and hence the drilling cost – is what we know as mud loss. The mud loss can be prevented or at least significantly reduced by taking proper measures beforehand provided the position and intensity of such loss can be properly predicted using an accurate predictor model. Accordingly, in this study, we used the convolutional neural network (CNN) and hybridized forms of multilayer extreme learning machine (MELM) and least square support vector machine (LSSVM) with the Cuckoo optimization algorithm (COA), particle swarm optimization (PSO), and genetic algorithm (GA) for modeling the mud loss rate based on drilling data, mud properties, and geological information of 305 drilling wells penetrating the Marun Oilfield. For this purpose, we began by a pre-processing step to attenuate the effect of noise using the Savitzky-Golay method. The whole set of available data was divided into the modeling (including 2300 data points) and the validation (including 483 data points) subsets. Next, the second generation of the non-dominated sorting genetic algorithm (NSGA-II) was applied to the modeling data to identify the most significant features for estimating the mud loss. The results showed that the prediction accuracy increased with the number of selected features, but the increase became negligible when the number of selected features exceeded 9. Accordingly, the following 9 features were selected as input to the intelligent algorithms (IAs): pump pressure, mud weight, fracture pressure, pore pressure, depth, gel 10 min/gel 10 s, fan 600/fan 300, flowrate, and formation type. Application of the hybrid algorithms and simple forms of LSSVM and CNN to the training data (80% of the modeling data, i.e. 1840 data points) showed that all of the models tend to underestimate the mud loss at higher mud loss rates, although the CNN exhibited lower underestimation levels. Error analysis on different models showed that the CNN provided for a significantly higher degree of accuracy, as compared to other models. The more accurate outputs of the hybrid LSSVM model than those of the simple LSSVM indicated the large potentials of metaheuristic algorithms for achieving optimal solutions. The lower error levels obtained with the CNN model in the testing phase highlighted the excellent generalizability of this model for unseen data. The more accurate predictions obtained with this model, rather than the other models, in the validation phase further proved this latter finding. Therefore, application of this method to other wells in the same field is highly recommended.

Gas cap blow down strategy is normally deployed for Ultra-thin oil rim reservoirs with huge gas caps due to extremely high gas oil ratios from wells in such reservoirs. The current state leads to loss of production from the oil reserves due to high initial reservoir pressure thus, reducing its net present value. Data on important factors essential to the productivity of oil rim reservoirs are used to build a heterogeneous ultra-thin reservoir with a time step of 10,000 days using the Eclipse software and its embedded correlations. The reservoir is subjected to a gas cap blowdown via a gas well, then an oil well is initiated into the model at onset and after time periods of 2000 days, 4000 days, 6000 days and 8000 days to estimate the oil recovery. It is expected that due to the large nature of the gas cap, pressure decline will be drastic and leading to a low oil recovery, hence the injection of water and gas at different rates at the periods indicated. The results indicate an oil recovery of 4.3% during gas cap blow down and 10.34% at 6000 days. Peak oil recoveries of 12.64% and 10.80% are estimated under 30,000 Mscf/day at 4000 days and 1000 stb/day at 6000 days respectively. This shows an incremental oil recovery of 8.34% and 6.5% over that recorded during gas cap blow down. The results also indicate that the gas production at those periods was not greatly affected with an estimated increment of 257 Bscf recorded during 30,000 Mscf/day at 4000 days. All secondary injection schemes at the respective time steps had positive impact on the overall oil recoveries. It is recommended that extra production and injection wells be drilled, enhanced oil recovery options and injection patterns be considered to further increase oil recovery.

For reservoirs with abnormally high pressure and high geostress, formation resistivity can be greatly affected. This increase of resistivity resulting from high stress causes errors in the identification of reservoir fluids. In order to investigate the effect of stress on resistivity, resistivity measurement was conducted simultaneously with triaxial testing to obtain rock resistivity under high temperature and high pressure. The changes of resistivity and resistivity increasing coefficient with horizontal differential stress and minimum horizontal stress were revealed from experiments. Besides, field data were analyzed to show the main influencing factors of formation resistivity under reservoir conditions. In addition, a new resistivity correction model for high geostress formation was derived in this work. The interpretation results are in good agreement with well testing data in the Keshen area of the Tarim oilfield, China.

The nature of carbonate reservoirs promotes the adsorption of oil onto the rock surface hence making oil recovery a challenge even with the interventions of varied chemical EOR methods. Recently, low salinity water flooding has become of great interest since it is cost-effective and environmentally friendly. Although low salinity waterflooding has been highly investigated in sandstone reservoirs, it is not the same for carbonate reservoirs due to its complexities. Nonetheless, it has been proposed as a favourable technique to mobilise the trapped oil in carbonate reservoirs. Wettability alteration is regarded as the most accepted mechanism for low salinity flooding but has not been well understood making field scale applications doubtful. In this paper, we present a detailed review of the wettability alteration mechanisms in carbonate reservoirs during low salinity waterflooding. Parameters influencing wettability alteration in carbonates and the interactions that occur at the rock/brine/oil interface are also presented. The different methods utilised for wettability measurements during low salinity waterflooding are also reviewed including their drawbacks and advantages and recommendations. This will provide an improved understanding of the low salinity flooding application in carbonate reservoirs.

The present work studies the influence of oil pipe joint passing through annular blowout preventer (BOP) on its sealing performance in high pressure gas wells under snubbing service. When the oil pipe joint passes through the BOP, due to the change of its structure, it is easy to cause the rubber core seal failure of the BOP, resulting in the leakage of toxic and harmful gas in the well, which seriously threatens the safety of the operators. Aiming at the problem of gas leakage caused by rubber core seal failure of annular BOP, based on the rubber large deformation theory and rubber core seal mechanism, a dynamic finite element model of rubber core-oil pipe joint is established, and the correctness of the model is verified by comparing the failure of rubber core on site; The results show that when the oil pipe joint passes through the BOP, a sealing buffer zone (SBZ) will be formed at the upper and lower shoulder of the joint, and the contact stress of the rubber core will decrease by 10 MPa–30 MPa; Because of the funnel effect of the rubber core, the damage of the rubber core caused by the running oil pipe joint of the BOP is greater than that caused by the lift oil pipe joint; When lifting oil pipe, the existence of SBZ is easy to cause gas leakage in the well; The optimized structure of oil pipe joint with small inclination and long shoulder can significantly reduce the influence of SBZ on the sealing performance of BOP. The research work in this paper is of great significance to improve the dynamic sealing performance of BOP.

During the solid fluidization exploitation of marine natural gas hydrates, the hydrate particles and cuttings produced via excavation and crushing are transported by the drilling mud. The potential flow safety issues arising during the transport process, such as the blockage of pipelines and equipment, have attracted considerable attention. This study aims to investigate the impact of hydrate adhesion features, including agglomeration, cohesion, and deposition, on the flow transport processes in solid fluidization exploitation and to provide a reference for the design and application of multiphase hydrate slurry transport in solid fluidization exploitation. We established a numerical simulation model that considers the hydrate adhesion properties using the coupled computational fluid dynamics and discrete element method (CFD-DEM) for the multiphase mixed transport in solid fluidization exploitation. An appropriate model to simulate the adhesion force of the hydrate particles and the corresponding parameter values were obtained. The conclusions obtained are as follows. Under the same operating conditions, a stationary bed is more likely to form in the transport process due to the hydrate adhesion forces; adhesion forces can increase the critical deposition velocity of the mixture of hydrate particles and cuttings. Hydrate adhesion lowers the height of the solid-phase moving bed, while the agglomeration and cohesion of particles can intensify the aggregation and deposition of hydrate debris and cuttings at the bottom of the pipe. These particles tend to form a deposit bed rather than a moving bed, which reduces the effective flow area of the pipeline and increases the risk of blockage.

Based on corrosion thermodynamics and kinetics, considering the multi-field coupling effects of fluid flow, electrochemical reaction and mass transfer process, a new corrosion prediction mechanistic model was proposed by introducing the influence factor of corrosion product film on diffusion coefficient of ion mass transfer, which is based on the CO₂ corrosion prediction model proposed by Nesic et al. The influence of temperature, flow rate and pH value on CO₂ corrosion behavior on 20# steel was studied by orthogonal tests. Scanning electron microscopy (SEM) and energy spectrum analysis (EDS) was used to analyze the surface and cross section morphology of the corrosion product film, and the thickness of the corrosion product film was measured. The results show that the introduced influence factor can simplify the ion mass transfer calculation in the presence of corrosion product film, and the relative error between the predicted value of the modified model and the experimental results is satisfactorily controlled less than 10%. Compared with the prediction model without considering the influence of corrosion product film, the influence factor can effectively correct the high prediction value of the mechanistic model under the influence of corrosion product film, improve the accuracy and applicability of corrosion prediction, and provide important theoretical guidance for the design, manufacturing, operation and maintenance of oil and gas production pipelines and related facilities.

Oil exploration and production, well stability, sand production, geothermal drilling, waste-water or CO₂ sequestration, geohazards assessment, and EOR processes such as hydraulic fracturing, require adequate information about in-situ stresses. There are several methods for analyzing the magnitude and direction of in-situ stresses. The evaluation of tensile fractures and shear fractures in vertical oil and gas wellbores using image logs is one of these methods. Furthermore, when image logs are run in boreholes, they can be extremely costly and possibly stop the drilling. The data for this study were gathered from seven directional wells drilled into a strike-slip fault reservoir in southern Iran. Vertical stress, minimum horizontal stress, pore pressure, Poisson's ratio of formations, and 233 mud loss reporting points make up the entire data. This is the first time maximum horizontal stress direction has been calculated without referring to image log data. In addition, the points of lost circulation were categorized into natural and induced fracture. The results revealed that, the maximum horizontal stress direction of the reservoir was calculated at 65° northeast-southwest. The error rate is roughly 10° when comparing the results of this investigation to those obtained from the image log. The maximum horizontal stress direction is calculated precisely. In terms of tensile fracture pressure, the in-situ stress ratio identifies the safest as well as the most critical inclination and azimuth for each well.

Hydraulic fracturing (HF) is a commonly used technique to stimulate low permeability formations such as shale plays and tight formations. However, this method of well stimulation has also been used in high permeable unconsolidated sandstone formations to bypass near-wellbore formation damage and prevent sand production at some distance apart from the wellbore wall. The treatment is called frac-pack completion, where a short length but wide width fracture is formed by injecting aggressive concentrations of proppant into the fracture plane. This operation is known as tip screen-out (TSO). Detailed design of fluid and proppant, including an optimal pump schedule, is required to achieve satisfactory TSO. In this study, we first assess the lattice-based numerical method's capabilities for simulating hydraulic fracturing propagation in elastoplastic formation. The results will be compared with the same case simulation results using a pseudo 3D (P3D) model and analytical model. Second, we explore the Nolte (1986) design for frac-pack and TSO treatment using lattice-based software and the P3D model. The results showed that both models could simulate the hydraulic fracturing propagation in soft formation and TSO operation, while some differences were observed in generated geometry, the tip screenout time and net pressure profiles. The results are presented. It was noted that fracture propagation regime (viscosity/toughness), nonlocality and nonlinearity had an influence on the different geometries. The advantages of each model will be discussed.

Yaha condensate gas reservoir is condensate gas reservoir developed by gas injection in the Tarim Basin. The practice of gas injection in condensate gas reservoir shows that the key to improve gas injection effect is to control gas channeling. Dynamic monitoring shows that there is no instantaneous miscibility between dry gas and condensate gas during gas injection. Based on the principle of entropy increase and mass transfer kinetics, the phase behavior of condensate gas and dry gas in reservoir is analyzed theoretically. The new technique to improve condensate recovery is adopted for condensate gas field. By using the density difference and seepage characteristics of dry gas and condensate gas, the injected dry gas cap is formed at the top of the gas reservoir, and the three-dimensional displacement is realized by the expansion of dry gas cap. Gas injection gravity assisted flooding technology is to realize vertical displacement of injected gas through the expansion of dry gas cap by using gravity differentiation caused by gas density difference. This technology can keep the front edge of gas injection advance evenly and solve the problem of gas channeling in the process of cyclic gas injection.