Petroleum最新文献

Marine unbonded flexible pipes serve as the most essential equipment in offshore oil and gas exploration and exploitation. Axial compressive loads during installation or in service in the complex marine environment usually lead to buckling failure. A flexible pipe is a composite structure with multiple functional layers, of which the tensile armor layer plays a key role with regard to the response of the pipe subjected to axial loads. In this paper, a simplified three-dimensional finite element model is developed, focusing on the tensile layer and replacing the carcass layer, pressure sheath layer, and pressure armor layer by a cylindrical rigid body to reduce computational expense. By using this model, the buckling failure modes of the tensile armor layer (in particular the birdcaging phenomenon) are analyzed. Several key parameters that affect the stability of the flexible pipe under axial compression and torsion are emphasized, and their effects on its axial and torsional stiffness are compared and discussed. The results show that both the lay angle of the steel wires and the interlayer friction coefficient have a significant influence on the axial and torsional stiffness of the pipe, whereas the damaged length of the outer sheath has virtually no effect.

Surfactant injection is a well-established method of chemical EOR processes. Surfactant adsorption into clay layers can prevent their proper performance and thus reduce the oil recovery factor. On the other hand, this adsorption property of clay materials can be used to prevent surface and underground water pollution and reduce soil pollution. In this experimental study, the effect of surfactant concentration, electrolyte type (NaCl and MgCl₂), and the solution salinity on fluid adsorption into the interlayer space of different clay types (bentonite and kaolinite) was investigated. XRF analysis was conducted on two relevant clay samples, and immersion and Washburn tests were performed on the desired samples with the Sigma 700 setup. Then, according to the clay type, the most optimal conditions were introduced for the surfactant solution used in the two areas of EOR and environmental processes related to reducing soil pollution. In the EOR processes, the optimal condition for the lowest adsorption amount is C (with 1 CMC concentration and salinity of 100,000 ppm for NaCl salt). This fluid works better in kaolinite formations. In the environmental field related to the reduction of soil pollution, if the pollutants we are looking for are R and S (with alkyl benzene sulfonic acid as the dominant agent), bentonite has a better performance than kaolinite in terms of adsorption and subsequently pollution control. If the polluting fluid contains MgCl₂ ions in the exact salinity values, the adsorption amount and soil pollution control will be higher for both adsorbent clays than if our fluid has NaCl salinity. The study's findings have a wide range of applications in surfactant flooding designs, surfactant adsorption optimization, and can be generalized to other detergent types.

Sand production along with the oil/gas detrimentally affects the oil production rate, downhole & subsurface facilities. Mechanical equipment and various chemicals like epoxy resin, furan resin, phenolic resin, etc. are used in the industry to reduce or eliminate this problem. In the present study, a blend of organic and inorganic silicates are used to consolidate loose sand in the presence and absence of crude oil using a core flooding apparatus. The effects of chemical concentration, pH, curing temperature and time, and the presence of residual oil on the consolidation treatment results such as compressive strength and permeability retention, were investigated and optimized. FT-IR and FE-SEM characterization techniques were employed to investigate the interaction between the chemical molecules and the sand grains. The current binding agent exhibited a viscosity of less than 6 cP at room temperature, which facilitates efficient pumping of binding agent into the desired formation through the well bore. The developed mixture demonstrated consolidation properties across all pH conditions. Furthermore, during the experimental investigation, the curing time and temperature was carefully optimized at 12 h and 423.15K, respectively to achieve the highest compressive strength of 2021 psi while achieving the permeability retention of 64%. The current chemical system exhibited improved consolidation capacity and can be effectively utilized for sand consolidation treatment in high-temperature formations.

The safety and efficiency of drilling engineering are greatly impeded by destructive vibrations of drill string in air drilling, such as stick-slip, bit-bounce and their coupled vibrations. To avoid or suppress these vibrations improving the stability of drilling operations, revealing the occurrence mechanisms of abovementioned harmful vibrations are indispensable by investigating dynamics characteristics of drill string system. In this paper, an axial-torsional coupled dynamics model that can capture the motion behaviors of bottom hole assembly (BHA) is established adopting the lumped parameter method. Subsequently, a rate of penetration (ROP) model appropriating for air drilling is obtained firstly by linear fitting means. Meanwhile, a novel discontinuous support model is established to describe the bit-formation interactions. Then, BHA dynamics are discussed using numerical simulations under different vibration scenarios: normal operation; stick-slip; bit-bounce; bit-bounce and stick-slip combination. Subsequently, in two drilling modes: the continuous and intermittent drilling, the vibration mitigation strategies and dynamics sensibility study of BHA are carried out based on the parametric analysis. The results show that increasing torsional stiffness of drill-pipes, appropriately adjusting rotation speed of top driven system and dynamic weight on bit (WOB) are deemed as an effective strategy suppressing or eliminating stick-slip and bit-bounce vibrations of BHA. Suggest that the rotation speed of top driven system and dynamic WOB are 5 rad/s and 3.5 kN, respectively. Finally, the constructed probability maps allow to driller to choose reasonable mechanical parameters, thereby realizing smooth drilling operation in the air drilling.

Polymer gel was widely used as water shutoff agent in mature oil fields. And the results of single-phase plugging experiments show that the plugging rate of the polymer gel to the oil phase is lower than that of the water phase. However, the disproportionate permeability reduction (DPR) mechanism of polymer gels still remains controversial. In this paper, we used four gel formulations including polyethyleneimine (PEI) and phenol-formaldehyde crosslinked gel with and without adding laponite to investigate the effect of gel elastic property on the water shutoff mechanism. The result of sand pack flooding experiments shown that the gel with higher elastic modulus has better effects on decreasing water cut and increasing oil recovery. After adding laponite, the elastic modulus of phenol-formaldehyde crosslinked gel increased from 64.2 Pa to 192 Pa, and the elastic modulus of PEI crosslinked gel increased from 27.4 Pa to 36.5 Pa. Compared to the phenol-formaldehyde-HAPM gel, the oil recovery of laponite-phenol-formaldehyde-HPAM gel increased by 5.2% and the maximum water cut decreased by 8.3%. Besides, comparing with PEI-HPAM gel, the oil recovery of laponite-PEI-HPAM gel increased by 2.7% and the water cut dropped by 27.8%. In the meanwhile, the laponite-phenol-formaldehyde-HPAM gel with higher elastic modulus obviously swells in the formation water but almost remains constant in oil at 105°C. The mass of gel soaked in the formation water increased from 42 g to 96 g and the gel volume increased by 300% within 48 hours. This study improves the understanding of the DPR mechanism of polymer gel for water shutoff.

The sedimentary environment of the Upper Triassic in the southeastern Sichuan Basin is obviously controlled by Luzhou paleo-uplift (LPU). However, the influence of paleo-uplift on the sedimentary patterns of the initial stages of this period in the southeastern Sichuan Basin has not yet been clear, which has plagued oil and gas exploration and development. This study shows that there is a marine sedimentary sequence, which is considered to be the first member of Xujiahe Formation (T₃X¹) in the southeastern Sichuan Basin. The development of LPU resulted in the sedimentary differences between the eastern and western Sichuan Basin recording T₃X¹ and controlled the regional sedimentary pattern. The western part is dominated by marine sediments, but the eastern paleo-uplift area is dominated by continental sedimentation in the early stage of T₃X¹, and it begins to transform into a marine sedimentary environment consistent with the whole basin in the late stage of the period recorded by the Xujiahe Formation. The evidences are as follows: (1) time series: based on the cyclostratigraphy analysis of Xindianzi section and Well D2, in the southeastern Sichuan Basin, the period of sedimentation of the Xujiahe Formation is about 5.9 Ma, which is basically consistent with the Qilixia section, eastern Sichuan basin, where the Xujiahe Formation is widely considered to be relatively complete; (2) distribution and evolution of palaeobiology: based on analysis of abundance evolution of major spore-pollen, many land plant fossils are preserved in the lower part of T₃X¹, indicates the sedimentary environment of continental facies. In the upper part of T₃X¹, the fossil of terrestrial plants decreased, while the fossil of marine and tidal environment appeared, this means that it was affected by the sea water in the late stages of T₃X¹; (3) geochemistry: calculate the salinity of water from element indicates that the uplift area is continental sedimentary environment in the early stage of T₃X¹, while the central and western areas of the basin are marine sedimentary environment. Until the late stage of T₃X¹, the southeast of the basin gradually turns into marine sedimentary environment, consisting with the whole basin; (4) types of kerogen: type Ⅲ kerogen representing continental facies was developed in the early stage of T₃X¹ in the uplift area, and type Ⅱ kerogen, representing marine facies, was developed in the late stage; while type Ⅱ kerogen was developed in the central and western regions of the basin as a whole in T₃X¹. This study is of great significance for understanding of both stratigraphic division and sedimentary evolution providing theoretical support for the exploration and development of oil and gas.

Polycrystalline diamond compact (PDC) bit is one of the most widely used drill bits for improving the rate of penetration in deep oil and gas well and geothermal well. However, the dynamic rock fragmentation mechanics characteristics of PDC bits are still unclearly. A coupled fragmentation mechanics model of PDC cutter-rock interaction is established by combining the mixed fragmentation modes with dynamic strength. The coupling influence laws of cutter angle, cutting depth, dynamic strength ratio, breaking modes on the horizontal force coefficient (HFC), vertical force coefficient (VFC) and specific energy are analyzed. The model of this paper can optimize cutter inclination angle, cutting depth and minimum specific energy. With the increase of the cutter inclination angle, the dynamic VFC changes into two modes. The definition of the dynamic modes depends on the dynamic strength ratio. As the cutting angle increases, the cutting force increases. The cutting force increases nonlinearly with increasing cutting depth. The specific energy of rock fragmentation increases nonlinearly with increasing cutting depth. With the increase of dynamic strength, the specific energy of rock fragmentation increases nonlinearly. When the input-energy increases, the rate of penetration response is divided into three stages. The results have important guiding significance for the PDC bit design and drilling parameters optimization to increase the rate of penetration and the efficiency of exploration and development.

Water injection for oil displacement is one of the most effective ways to develop fractured-vuggy carbonate reservoirs. With the increase in the number of rounds of water injection, the development effect gradually fails. The emergence of high-pressure capacity expansion and water injection technology allows increased production from old wells. Although high-pressure capacity expansion and water injection technology has been implemented in practice for nearly 10 years in fractured-vuggy reservoirs, its mechanism remains unclear, and the water injection curve is not apparent. In the past, evaluating its effect could only be done by measuring the injection-production volume. In this study, we analyze the mechanism of high-pressure capacity expansion and water injection. We propose a fluid exchange index for high-pressure capacity expansion and water injection and establish a discrete model suitable for high-pressure capacity expansion and water injection curves in fractured-vuggy reservoirs. We propose the following mechanisms: replenishing energy, increasing energy, replacing energy, and releasing energy. The above mechanisms can be identified by the high-pressure capacity expansion and water injection curve of the well HA6X in the Halahatang Oilfield in the Tarim Basin. By solving the basic model, the relative errors of Reservoirs I and II are found to be 1.9% and 1.5%, respectively, and the application of field examples demonstrates that our proposed high-pressure capacity expansion and water injection indicator curve is reasonable and reliable. This research can provide theoretical support for high-pressure capacity expansion and water injection technology in fracture-vuggy carbonate reservoirs.

Due to the increased demand for energy resources these days, especially due to the Russian-Ukrainian war, the focus of the major countries is turning strongly towards improving oil production, especially heavy and extra heavy oil, which represents 40% of the world oil reserve. Steam-based and thermal (EOR) procedures are promising techniques for recovering heavy oil reservoirs, but they suffer from a sequence of problems and complications that arise after long-term application. These complications comprise steam breakthrough, steam overlap, and steam/rock interactions. This research presents the currently applied techniques to maximize the productivity of heavy oil, such as steam injection, cyclic steam stimulation, in-situ combustion, and steam-assisted gravity drainage. Thermal technologies face numerous obstacles, as they are energy and water-intensive processes that are not environmentally friendly. The research also presents future trends in energy-saving and environmentally friendly techniques that enhance heavy oil recovery through vapor extraction (VAPEX) steam-solvent hybrid techniques, electromagnetic energy, sonication, and nanotechnology. The findings of this review reported that all the presented techniques focus on how to reduce the oil viscosity and in-situ upgrade the crude oil properties. In turn, these enhance both the productivity rate and oil recovery and minimize the production cost. This article can be considered a comprehensive review of thermal recovery methods in heavy and extra-heavy oil, in addition to screening criteria used for each method.

Hydraulic fracturing is the primary method used for oilfield stimulation, and the migration and settlement pattern of proppant plays a crucial role in the formation of high conductivity propping fractures in the reservoir. This study summarizes two growth modes of sand dune: the ‘overall longitudinal growth’ mode and the ‘push growth along fracture length direction’ mode. To investigate these modes, a two-phase velocity test is conducted using PIV, and the exposure difference is utilized to separate the tracer and track the single-phase velocity. By analyzing the slickwater flow field and proppant velocity field, the micro-motion mechanism behind the two dune growth modes is quantitatively examined. The results indicate that mode 1 growth of the sand dune occurs when a pump with a large mesh number, high polymer viscosity, and large displacement is used. On the other hand, mode 2 growth is observed when a pump with a small mesh number, low polymer viscosity, and small displacement is employed. It is important to note that there is no clear boundary for the migration and sedimentation mode of proppant, as they can transition into each other under certain conditions. These modes only exist during specific stages of sand dune growth. In the case of the ‘backflow’ pattern, the settlement of proppant is primarily influenced by the vortex structure of slickwater. Conversely, in the ‘direct’ pattern, the proppant is propelled forward by the drag of the fluid and settles due to its own gravity. Once the proppant placement reaches equilibrium, the direction of proppant velocity follows a normal distribution within 0°. This approach establishes a connection between the overall placement of the sand dune and the microscopic movement of the proppant and slickwater. Optimizing construction parameters during fracturing construction can enhance the effectiveness of distal proppant placement in fractures.