High-pressure Formation Research Articles

Taming the Thunder Horse With Axes and Vectors

The Thunder Horse Field targets Middle Miocene deepwater turbiditic reservoirs. Despite being prolific, the mapping of the ~180 m thick, partly amalgamated reservoir sandstones is challenging. Seismic quality is reduced by the presence of salt structures. The salt overburden and high formation pressure require the use of heavy mud weights and oil-based drilling fluids, which limit the resolution and interpretation potential of borehole image logs (BHI). Halokinetic movements caused significant post-depositional deformation of the already complex gravity-driven sediment stack, and the reservoir beds drape against an E-W oriented salt wall. Consequently, the assessment and removal of the structural dip component are not trivial, and the evaluation of paleo-transport directions is considerably more complicated compared to undisturbed deepwater reservoirs. This paper illustrates the potential of eigenvector methods to BHI from Ruehlicke et al. (2019) for reconstructing the depositional slope and the architecture of mass transport complexes in the case of chaotic depositional settings and uncertain structural dip. Figures from Henry et al. (2018) are used wherein part axial analysis was performed on data from a group of Thunder Horse wells and presented in more detail.

Experimental study on the effect of oil based filtercake on bonding strength at wellbore second interface

The integrity of the oil-gas wellbore is critically depending on the quality of the binding between cement and rock materials. Weak bond between cement and formation may lead to the potential leakage of high-pressure formation fluids through cracks and micro-annulus formed at the interface which results into blowout and groundwater contamination. Failure to properly displace mud prior to cementing can lead to poor bonding at the second interface (SI) of the wellbore. The main purpose of this study is to quantify the impact of oil based-filtercake on the bonding quality at the wellbore Second Interface during the drilling of sandstone reservoir well by using shear bond measurements and material characterization techniques. The results indicated that, the presence of oil based-filtercake at the SI has a detrimental effect on shear bond strength making it as weakest point of adhesion. The tested Blank samples had higher bond strength compared to treated (oil based filtercake) samples. The low bond strength for filtercake system was due to existence of oil based filtercake films which hindered the totally cement hydration process to form a strong bond as the oily film cannot allow the interact with aqueous cement slurry material to complete the hydration process. The FTIR analysis showed that, the lower transmittance (35%) at 1091 cm−1 band (Si–O) of mud treated samples revealed the low content of chemical binder material (Calcium Silicate Hydrate - CSH) at the interface while the blank samples gave 62% at 1088 cm−1 band (Si–O) showing the high content of CSH at the interface which led high bond strength. The results show that oil-based filtercake has a significant detrimental effect on shear bond strength of the second interface.

Water Saturation Calculation and Fracture Type Identification of a Buried Hill Fractured Reservoir

Abstract A buried hill reservoir is a special type of bedrock reservoir, in which fractures are the important reservoir space and main percolation path. However, due to the characteristics of the buried hill reservoir such as deep burial depth and high formation pressure, the fracture width of deep formation is generally in micron level, and the randomness of spatial development brings great difficulties to logging identification and reservoir parameter calculation. Based on the fracture porosity and saturation model of the dual pore model, this paper puts forward the theory of identifying fracture type of buried hill fractured reservoir by using conductivity efficiency. The results show that (1) the fracture angle has no effect on the conductivity efficiency. And we cannot distinguish a high-angle fracture from a low-angle fracture by conductivity efficiency. (2) The values of porosity and water saturation are not directly related to the conductivity efficiency. But porosity and water saturation will affect the connectivity of water in the reservoir and indirectly affect the conductivity efficiency. (3) The conductivity efficiency of the network fracture is usually less than that of the dissolution fracture.

Perforation location optimization through 1-D mechanical earth model for high-pressure deep formations

Optimum perforation location selection is an important study to improve well production and hence in the reservoir development process, especially for unconventional high-pressure formations such as the formations under study. Reservoir geomechanics is one of the key factors to find optimal perforation location. This study aims to detect optimum perforation location by investigating the changes in geomechanical properties and wellbore stress for high-pressure formations and studying the difference in different stress type behaviors between normal and abnormal formations. The calculations are achieved by building one-dimensional mechanical earth model using the data of four deep abnormal wells located in Southern Iraqi oil fields. The magnitude of different stress types and geomechanical properties was estimated from well-log data using the Techlog software. The directions of the horizontal stresses are determined in the current wells utilizing image-log formation micro-imager (FMI) and caliper logs. The results in terms of rock mechanical properties showed a reduction in Poisson’s ratio, Young modulus, and bulk modulus near the high-pressure zones as compared to normal pressure zones because of the presence of anhydrite, salt cycles, and shales. Low maximum and minimum horizontal stress values are also observed in high-pressure zones as compared to normal pressure zones indicating the effects of geomechanical properties on horizontal stress estimation. Around the wellbore of the studied wells, formation breakouts are the most expected situation according to the results of the wellbore stress state (effective vertical stress (σzz) > effective tangential stress (σθθ) > effective radial stress (σrr)).

On the initial mass–radius relation of stellar clusters

ABSTRACT Young stellar clusters across nearly five orders of magnitude in mass appear to follow a power-law mass–radius relationship (MRR), $R_{\star }\propto M_{\star }^{\alpha }$, with α ≈ 0.2–0.33. We develop a simple analytic model for the cluster mass–radius relation. We consider a galaxy disc in hydrostatic equilibrium, which hosts a population of molecular clouds that fragment into clumps undergoing cluster formation and feedback-driven expansion. The model predicts a mass–radius relation of $R_{\star }\propto M_{\star }^{1/2}$ and a dependence on the kpc-scale gas surface density $R_{\star }\propto \Sigma _{\rm g}^{-1/2}$, which results from the formation of more compact clouds (and cluster-forming clumps within) at higher gas surface densities. This environmental dependence implies that the high-pressure environments in which the most massive clusters can form also induce the formation of clusters with the smallest radii, thereby shallowing the observed MRR at high-masses towards the observed $R_{\star }\propto M_{\star }^{1/3}$. At low cluster masses, relaxation-driven expansion induces a similar shallowing of the MRR. We combine our predicted MRR with a simple population synthesis model and apply it to a variety of star-forming environments, finding good agreement. Our model predicts that the high-pressure formation environments of globular clusters at high redshift naturally led to the formation of clusters that are considerably more compact than those in the local Universe, thereby increasing their resilience to tidal shock-driven disruption and contributing to their survival until the present day.

The method for prediction of formation pore pressure based on mechanical specific energy theory

With traditional prediction methods, the accuracy for prediction of formation pressure is low in formations with complex lithology, such as saline aquifers, fractured formations and carbonate rocks. Therefore, in Qinghai Oilfield, in order to ensure the drilling safety, studies have been conducted in order to find the method for predicting the pore pressure of E32 formation, in which the lithology is complex. Mechanical specific energy is the total energy required for breaking and removing rock per unit volume. With the increase of depth, the confining pressure of rock and vertical effective stress increase. Therefore, more energy is required to break and remove rock per unit volume. However, in abnormal high-pressure formation, pore fluid bears some overburden pressure, and the rock effective stress is reduced, leading to less requirement for mechanical specific energy. Therefore, it is feasible to evaluate the formation pressure qualitatively based on the mechanical specific energy theory. In this study, according to the actual drilling conditions, a model for prediction of formation pressure has been constructed and optimized on the basis of mechanical specific energy theory. With this model, the prediction accuracy on formation pressure has been improved obviously. This model has been used in prediction of formation pressure of the E32 formation in several wells in Qinghai Oilfield, which are carbonate rocks with fractures developed. The application results show that this formation pressure prediction model based on the mechanical specific energy works well in prediction of formation pore pressure, with an error less than 12%, which meets the engineering requirements. It provides a new method for predicting the pore pressure in complex lithologic formations such as carbonate rocks.

Computational flow analysis of a single peristaltic wave propagation in the ureter

Background and objectiveThe bladder receives the urine from the kidney and ureter. The series of peristaltic waves facilitate urine transport to the bladder. The peristaltic flow in the ureter is associated with fluid trapping and material reflux, which may cause an increase in bladder pressure. It is difficult to visualize the complex peristalsis phenomenon, in the ureter using image and radiography experiments. A numerical simulation will help in the understanding of urine bolus formation and its effect on the ureter wall. MethodsA three-dimensional computational fluid dynamic analysis is carried out to understand the flow physics associated with bolus formation and the effect of reflux on the ureter. ANSYS-CFX, a commercially available computational dynamics package is used to simulate the peristalsis. A single sinusoidal peristaltic wave traveling along a circular tube will yield the velocity, pressure, wall shear stress distributions inside the ureter. ResultsThe propagation of the peristaltic wave results in the backflow of urine near the inlet at the beginning of the flow. As the wave propagates towards the outlet, the flow rate decreases. It is observed that pressure distribution along the ureter axis will deteriorate towards the outlet. The contraction produces a very high-pressure gradient which causes the urine backflow. The trapping and the bolus formation cause a significant rise in bolus pressure, simultaneously developing negative pressure at the contraction neck. ConclusionsThe effect of peristalsis on the ureter biofluid dynamic behavior of the ureter is visualized in this study. It is established that the peristaltic contraction results in high-pressure formation at the bolus and negative pressure at the neck. It was found to be a maximum of 1.1 Pa at the bolus center and —1.13 Pa at the neck region. At the ureter pelvis junction, a higher wall shear of 0.095 Pa is observed as the wave starts to propagate. The velocity vectors show that the trapping of urine causes reflux and results in an adverse pressure gradient near the wall. A maximum pressure gradient of 485 Pa/meter was observed at the contraction of the ureter wall.

Passive seismic data processing methods to identify contrast intrasalt interlayers in the geological section of the Astrakhan Arch

The article examines the problem of processing microseismic noise (MN) to identify and evaluate occurrence depth of contrasting geological objects – intersalt interlayers with a potentially high formation pressure. If it is impossible to use artificial wave sources, statistic processing of passive seismic data becomes critical. Due to the accumulation of power spectral density (PSD) during a long-term recording of MN the deterministic medium effect on a random signal spectrum is identified. PSD modulation when the surface or the bottom of the layered medium is exposed to white noise is expressed in terms of the Green’s function (GF) of a wave equation. Relevant GF variations corresponding to the layers form the basis for accumulated PSD approximation, and indicate the depth and contrast of the target features.

The modeling of geofluidal pressures by electrometric logging data

The paper reviews one of the most urgent issues – the study of geofluidal pressures, as well as the investigation of the zone of abnormally high formation pressure and its quantitative estimation. The modeling of geofluidal pressures has been carried out in the research based upon the electrometric logging data of the wells. Applied method allows to identify the zone of abnormally high formation pressure more precisely and evaluate it quantitatively based on the geophysical well logging data.

A new method for reasonable injection production ratio calculation of considering external flow volume

The phenomenon of high injection production ratio and low formation pressure maintenance level are common in peripheral oil fields of Daqing oilfield. It is considered that the outflow of water injection exists in the reservoir. In this paper, the optimal mathematical model is established with the maximum oil production as the objective function and the injection pressure and flowing pressure as the constraints. Based on the material balance equation considering the overflow water, the calculation formula of formation pressure changing with time, and other parameters changing such as injection production ratio are derived. The reasonable interval injection production ratio in a block can be obtained by the iterative method, which provides a theoretical basis for reasonable production and injection allocation in the middle-later stage of water drive reservoir development.

Structure–Reactivity Relationship in the High-Pressure Formation of Double-Core Carbon Nanothreads from Azobenzene Crystal

Structure–Reactivity Relationship in the High-Pressure Formation of Double-Core Carbon Nanothreads from Azobenzene Crystal

Filtration and structure of bentonite-β-cyclodextrin polymer microspheres suspensions: Effect of thermal aging time

Effective filtration loss control is a challenge for water-based drilling fluid when drilling high temperature and high pressure (HTHP) formations. After thermal aging at 200 °C for varying times, the static filtration loss controlling capabilities of β-cyclodextrin polymer microspheres (β-CDPs) and synthetic polymer Driscal-D in bentonite suspensions were compared in this study. A comprehensive physicochemical characterization was presented using Fourier transform infrared (FT-IR), X-ray diffraction (XRD), particle size distribution, zeta potential, electrical conductivity and scanning electron microscope (SEM). The results indicated that when exposure to thermal aging of 200 °C, the filtration loss of bentonite suspension increased with the initial 6 h of aging, after that it increased slightly. While for synthetic polymer Driscal-D, the filtration loss increased gradually with thermal aging time until to 36 h. In contrast for β-CDPs, the filtration loss increased firstly and then decreased and maintained relatively stable after thermal treatment for 6 h. High temperature destroyed the hydrated structure of bentonite particles and induced the increase of filtration loss volume. In viewing of Driscal-D, degradation of the polymer in combination with dehydration of bentonite particles led to the gradual losing of suspensions stability. For β-CDPs, after aging of 6 h, the hydrothermal carbonization reaction generated numerous nano and micro carbon spheres and bentonite-carbon sphere composited structures, which fill in the gaps between the larger particles and contribute to reducing the filter cake permeability. This result identified that β-CDPs are superior to synthetic polymer Driscal-D in filtration control when subjected to long term high temperature environments.

No observation of lead hydride in the Pb–H system under pressure up to 140 GPa

The possibility of high pressure formation of lead hydrides has been investigated through the direct reaction of lead with hydrogen in a laser-heated diamond anvil cell. Synchrotron x-ray diffraction was used to detect any structural changes and volume expansion due to hydrogen absorption in the Pb metal. The compression curve of lead embedded in helium, measured under the same experimental conditions, was used as a reference. No volume expansion of the Pb lattice was measured, hence indicating no formation of an interstitial hydride. The observed structural changes match those of pure lead with the sequence of compact structures fcc, hcp, and bcc. The PbH6 and PbH4 compounds, found by various crystal structure prediction calculations to be stable below 140 GPa, were not observed. Lead seems very reluctant to absorbing hydrogen, which could be used for plating materials to resist hydrogen embrittlement under extreme conditions.

Oilfield Water and Favorable Petroleum Exploration Targets for the Triassic Baikouquan Formation in the Slope of Mahu Depression, Junggar Basin

In this paper, we attempt to clarify the relationships between oilfield water and hydrocarbon distribution of the Triassic Baikouquan Formation, in the slope zone of Mahu depression, Junggar Basin, NW China, based on oilfield water mineralization degrees, diagenesis analysis, formation pressure coefficients, burial history, and thermal evolution processes. The results show that the study area can be divided into four zones according to the mineralization degrees, that is, (1) zone I: NaHCO3 + Na2SO4 type water with residual intergranular pores, porosity usually higher than 10%. The strata of zone I are generally buried shallow and influenced by leaching from atmospheric precipitation. This area contains normal edge and bottom water and has normal formation pressure coefficients (average 1.12); (2) zone II: CaCl2 type water with mainly compaction diagenesis, porosity usually less than 7% and high formation pressure coefficients (average 1.41); (3) zone III: NaHCO3 + CaCl2 type oilfield water with mainly feldspar dissolution diagenesis, porosity usually greater than 9% and high formation pressure coefficients (average 1.53); and (4) zone IV: CaCl2 type water, mainly compacted diagenesis with a few intergranular and feldspar dissolved pores, and high formation pressure coefficients (average 1.58). The mineralization degrees of the oilfield water in zone II, III, and IV are relatively high. The appearance of NaHCO3 type water in the deeply buried areas is usually related to oil and gas charging. Therefore, within the strata, deeply-buried areas (e.g., zone III), where NaHCO3 type water has been developed, are favorable targets for oil and gas exploration.

Predicting the critical drawdown pressure of sanding onset for perforated wells in ultra‐deep reservoirs with high temperature and high pressure

AbstractPerforated wells in ultra‐deep sandstone reservoirs are characterized by high reservoir temperature, high formation pressure, and high production, and sand production will cause severe safety hazards to these wells. Based on Drucker‐Prager (DP) rock failure criterion, a practical analytical model for predicting critical drawdown pressure (CDP) of sanding onset for perforated wells is established by comprehensively considering the influence of drag stress, formation water production, reservoir pressure depletion, temperature difference in the perforated wellbore. The proposed model is verified by field sanding onset monitoring data. The calculation results show that CDP changes with well inclination, and it decreases with the increase in wellbore temperature difference, reservoir pressure depletion, and water saturation. However, the CDP increases with the number of perforations and the ratio of diameter to length. The optimization of perforation parameters has an important influence on sand control. This study can effectively guide the prediction of CDP and provides basis for efficient and safe development of similar ultra‐deep and high yield sandstone reservoirs.

Study on Viscosity Reducer Flooding Technology for Deep Low Permeability Extra Heavy Oil Reservoirs

Deep low permeability extra heavy oil reservoir has the characteristics of high formation pressure, high crude oil viscosity, and low permeability. Conventional steam injection thermal recovery has poor viscosity reduction performance and low productivity of a single well, which makes it difficult to develop this type of heavy oil reservoir. In this paper, core flooding experiment and microvisualization equipment were used to study the mechanism of improving the recovery of deep extra heavy oil by using water-soluble viscosity reducer; the realization of water-soluble viscosity reducer in numerical simulation was achieved by using nonlinear mixing rule; the reservoir numerical simulation model of water-soluble viscosity reducer displacement in test well group was established to optimize the development technical parameter of water-soluble viscosity reducer. The results show that compared with waterflooding, the oil displacement efficiency of water-soluble viscosity reducer is increased by 12.7%; water-soluble viscosity reducer can effectively reduce the viscosity of extra heavy oil, under the same temperature and permeability, the higher the concentration of viscosity reducer, the better the viscosity reduction effect, and the smaller the pressure gradient required at the same injection rate; the main mechanism of water-soluble viscosity reducer for enhancing oil recovery is to form oil in water emulsion, which can reduce the viscosity and interfacial tension of crude oil and reduce the residual oil saturation; in the pilot well group, the optimized injection concentration of water-soluble viscosity reducer is 3%, and the optimal injection amount of water-soluble viscosity reducer solution is 50 t/d; water-soluble viscosity reducer displacement was implemented in the pilot well group, the average daily oil of well group was increased from 1.8 t/d to 7.34 t/d, and the pilot well group has achieved good development performance.

Modeling research on the extreme hydraulic extension length of horizontal well: impact of formation properties, drilling bit and cutting parameters

Horizontal well can increase well productivity and improve the economic benefit, which significantly promotes the development of shale gas, tight oil and heavy oil. Moreover, it plays an important role in the development of natural gas hydrate. Horizontal extension ability is one of the key indexes of horizontal well, but it is always impacted by formation properties and well structure. Therefore, a model is established to analyze the impact of formation properties and well structure as comprehensive as possible, which considers not only traditional influencing factors, like formation pressure and drilling bit parameters, but also other key factors, including cutting particle size, wellbore diameter and cross section. Based on the analysis, some advises are proposed for field application. The analysis indicates that horizontal well has stronger extension ability in the formation with low formation pressure and high fracture pressure, but it is still limited by pump pressure. Under-balanced drilling can strength the extension ability in high formation pressure by reducing drilling mud density. The natural fractures in formation should be noted when drilling long horizontal well. The extension length increases and then decreases with the cutting particle size, so cutting particle has optimal size for the horizontal extension length, which can be adjusted by the rate of penetration and rotation speed. The extension length increases first and then decreases with the gap between drilling string and hole. Considering the demand of rock breaking and cutting sweeping around drilling bit, it is not recommended to adjust the drilling bit parameters. Both the cutting bed height and drilling string eccentricity have impact on horizontal extension length by changing minimum cutting-carry pump rate and annular pressure drop. Under different combinations of above two parameters, minimum cutting-carry pump rate and horizontal extension length are determined by different factors and can be divided into three parts, including acceptable cutting bed height, cutting lifting efficiency, pump pressure and total circulation pressure loss and well bottom pressure and formation fracture pressure. The findings of this study can help for better understanding of horizontal well hydraulic extension length and optimization method.

Role of abnormally high formation pressures in the distribution of oil-gas bearing content in South Caspian depression

The paper reviews and compares the state of South Caspian depression to the large oil-gas bearing regions of the world genetically not associated but similar to the major geological factors. Geological data on the development and distribution of abnormally high formation pressures (AHFP) and anomaly ratio in the sections of sedimentary strata in various regions of the world has been analyzed. The appearance of abnormally high formation pressure in different geological conditions within South Caspian depression has been reviewed and compared to the corresponding results of similar basins, on the basis of which an adequate model developed as well. In the context of the fields with AHFP within South Caspian basin, it is shown that the significant amount of hydrocarbon reserves may be associated with AHFP zones. The paper presents a brief analysis of views development on the regulations of the distribution of hydrocarbon accumulations in the soil depth. Based on the graphic materials and mathematical statistics, the inequality of distribution of oil reserves on the territory of mentioned basins is justified. Therefore, data analysis on geobaric characteristics of perspective structures, particularly, in deep water zones of SCB, which is top priority for conducting exploration survey may contribute to more reasonable choice.

Influence of unconnected pores on effective stress in porous geomaterials: Theory and case study in unconventional oil and gas reservoirs

Unconventional oil and gas reservoirs are mostly characterized by unconnected pores and abnormal pore pressures. These conventional effective stress theories, such as Biot's theory, cannot display the quantitative relationship between unconnected pores' micro characteristics and the macro stress applied to the solid structure. These parameters related to the unconnected pores should be quantitatively incorporated in the effective stress formula. In this paper, two modified models were proposed to evaluate the solid framework's real effective stress and deformation. The effects of the unconnected pore pressure, unconnected porosity, and unconnected pore fluid's compressibility on effective stress and volumetric strain were theoretically investigated. It was found that the increase of unconnected pore pressure can decrease the effective stress and volumetric strain. For an abnormal high pore pressure formation, the growth of unconnected porosity can reduce the effective stress but increase the volumetric strain. The decrease of the unconnected pore fluid's compressibility can increase and decrease the effective stress and volumetric strain for abnormal low and high pore pressure reservoirs, respectively. Two case studies on the abnormal pore pressures induced by under-compaction and hydrocarbon generation were conducted. The results showed that the pore pressure exhibits significant increases when the unconnected pores and unconnected pore fluids are proactively compressed in the processes of under-compaction and hydrocarbon generation, respectively. The abnormal high pore pressures in these tight sandstone reservoirs in the Sichuan Basin, Tarim Basin, and Bohai Bay Basin can be theoretically generated when the pore space is compressed to 95%–84% of the initial pore space. The model can evaluate the effective stress and deformation for reservoirs with considerable unconnected porosities. In turn, it can also interpret the abnormal pressure generation induced by the changes of unconnected porosity and pore fluid's compressibility.

Main controlling factors for the enrichment of shale oil and significant discovery in second member of Paleogene Funing Formation, Qintong Sag, Subei Basin

Based on the study of hydrocarbon generation features, oil bearing property and reservoir property of shale in the second member of Paleogene Funing Formation in the Qintong Sag of the Subei Basin, the main controlling factors of shale oil enrichment were analyzed. Shale of the second member of Funing Formation in the Qintong Sag was featured by large-scale thickness and medium TOC content, which provided a material basis for shale oil enrichment. The vitrinite reflectance (%Ro) of shale in the second member of Funing Formation in the deep sag distributed between 0.9%-1.0%, indicating a moderate thermal evolution degree. Shale oil has the characteristics of light hydrocarbon, high gas-measured total hydrocarbon value and good fluidity. Few faults were developed, resulting in good preservation conditions and high formation pressure, which were conducive to hydrocarbon enrichment. High content of brittle minerals and well-developed lamella and natural fractures made formation fracturing easier. The continuous and large-area distribution of high-quality shale is the basis for oil and gas abundance. Preservation condition is the key factor to reservoir formation. The degree of evolution is a decisive factor of oil-bearing. High pressure, lamina development and high brittle mineral content are important factors for high yield. The shale oil in second member of Funing Formation in Shaduo area has the characteristics of low TOC content (1%), low gas oil ratio (40-80 m3/t) and high pressure (1.25 MPa). The success of this well has reduced the shale oil evaluation standard and threshold, and expanded the development space of shale oil.