Oil Gas Reservoirs Research Articles

Use of Petrochemical Products for Gas Shutting in Oil-Gas Reservoirs

A new method for preventing gas breakthroughs to producing well bottom during oil recovery from oil-gas condensate deposits, which enhances the efficiency of gas recovery technologies, is proposed. The method consists in use of hydrophobic gas shutting compositions based on furnace (residual fuel) oil. Filtration studies (physical modeling) of the gas shutting process were conducted for the proposed compositions. The gas breakthrough was simulated using permeable bulk porous media or permeable cores of productive bed of the reservoir.

Adaptability of Power Law Exponential Decline Model for Hydraulically Fractured Unconventional Reservoirs during and After Linear Flow

Reserve estimation of unconventional formations is a new challenge to reservoir engineers due to the geological uncertainty and complex flow patterns evolving in the multi-fractured horizontal wells (MFHWs). Some predicting models have been presented and widely used in MFHWs exhibiting a long-term linear flow, such as stretched-exponential production-decline (SEPD), power law exponential decline (PLE) and Duong’s model. Plenty of successful field applications of these models seem to have demonstrated their availability and correctness especially in the transient linear flow period. Due to the limitation of reservoir boundaries or size of stimulated volume, any fractured tight reservoir will eventually exhibit a boundary-dominated-flow (BDF). The models above which show “goodness of fit” in linear flow may not be used or will cause great error when used to predict production in BDF period. This paper compared the newly developed PLE model with the traditional Arps’ hyperbolic decline model in terms of production historic match, decline rate and decline exponent during and after linear flow. The analysis result demonstrated that PLE model actually cannot match production decline characteristics as previously thought when only linear flow appears and it is a model which should be used in the transition period rather than linear flow period as applied in the past few years. The wrong usage of the model will cause great error to reserve estimation. The modified steps to predict production in different flow pattern are given in this work. The outcome of this work should help the industry to forecast production and ultimate reserve more accurately in tight oil and shale gas reservoirs.

Local asymmetric fracturing to construct complex fracture network in tight porous reservoirs during subsurface coal mining: An experimental study

Hydraulic fracturing to enhance permeability of tight reservoirs is meaningful but difficult in constructing of complex fracture network. This study aimed to examine the effectiveness of tight porous reservoir stimulation in the context of hydraulic fracturing to increase the fracture complexity as much as possible. The simulation experiments were performed to reasonably establish the relation between the laboratory results and the field fracturing operations. Large size stratified and intact samples were casted to resist the size and boundary effects by mixing river sand and/or pulverized coal with concrete cement and freshwater in specific proportions. The samples with artificial slot orienting were casted to understand the fracture initiation, orientation, and deflection mechanisms considering the influence of caprock structure and re-fracturing without temporary plugging. The samples were tested under the scaled geostress conditions of corresponding in-situ stress with a true triaxial loading system, and the reasonable dimensionless groups derived from the literature. Consequently, this study proposed an asymmetric fracturing method based on the experimental results considering the scaling structure of overlying-reservoir-underlying in porous reservoirs. The local asymmetric fracturing is a type of reservoir stimulation method with small scale high-pressure fluids such as carbon dioxide，liquid nitrogen, water, etc., jet cutting to create slot and perforation for the aid of fracture initiation and orientation. Hydraulic fractures were influenced by the fracture-induced stress shadow and ratio of the maximum to minimum horizontal stress. The validation and comparative results showed that, compared with the re-fracturing, the asymmetric fracturing significantly increased the complexity of fracture network. Although the applicability of the asymmetric fracturing depending on the corresponding engineering pilots, the derived method could hopefully address the properties of the strata structure of the reservoirs efficiently. Therefore, it has a high potential for application in the fracturing of local underground coal seam and special-trap type oil gas reservoirs to construct fracture network.

Study On Prediction Technology Of Residual Oil In Prestack Seismic Inversion

The development adjustment of oil field, has entered a stage of determining drilling, and reservoir research focuses on the border of interwell narrow channel sand body position and the connecting relation between sand body. Based pre-stack inversion technique research, based on the seismic and geological results, combining with the construction, prestack inversion results, on the rock physical model test and choose suitable for the interpretation of the cutoff value of parameters, fine distribution of favorable reservoir characterization, analysis of oil gas reservoir, and then, the distribution of remaining oil prediction results, for the deployment of subsequent development Suggestions.

Cognitive seismic data modelling based successive differential evolution algorithm for effective exploration of oil-gas reservoirs

A cognitive modelling based new inversion method, the successive differential evolution (DE-S) algorithm, is proposed to estimate the Q factor and velocity from the zero-offset vertical seismic profile (VSP) record for oil-gas reservoir exploration. The DE algorithm seeks optimal solutions by simulating the natural species evolution processes and makes the individuals become optimal. This algorithm is suitable for the high-dimensional nonseparable model space where the inversion leads to recognition and prediction of hydrocarbon reservoirs. The viscoelastic medium is split into layers whose thicknesses equal to the space between two successive VSP geophones, and the estimated parameters of each layer span the related subspace. All estimated parameters span to a high dimensional nonseparable model space. We develop bottom-up workflow, in which the Q factor and the velocity are estimated using the DE algorithm layer by layer. In order to improve the inversion precision, the crossover strategy is discarded and we derive the weighted mutation strategy. Additionally, two kinds of stopping criteria for effective iteration are proposed to speed up the computation. The new method has fast speed, good convergence and is no longer dependent on the initial values of model parameters. Experimental results on both synthetic and real zero-offset VSP data indicate that this method is noise robust and has great potential to derive reliable seismic attenuation and velocity, which is an important diagnostic tool for reservoir characterization.

Analytical modeling of linear flow in single-phase tight oil and tight gas reservoirs

Unconventional reservoirs, including tight oil, tight gas and shale gas are economically attractive, but operationally challenging, particularly for cases when complex flow behavior occurs within the reservoir. Accounting for the physics of flow in such formations is central to providing improved short- and long-term oil and gas production forecasts. At the early phase of development of these reservoirs, and in the presence of limited data, analytical models are more suited for mechanistic studies leading to improved understanding of the reservoir. Analytical models often utilize solutions to flow equations for liquids with constant viscosity, and small and constant compressibility. In tight formations, however, these assumptions simply do not apply as fluid and rock properties change with pressure drawdown. Historically, efforts have concentrated on linearizing the governing partial-differential equations to account for these effects by employing appropriately defined pseudopressure and pseudotime functions. A rigorous approach for determination of pseudotime includes the use of average pressure in the distance of investigation during transient flow.In this work, an analytical expression for average reservoir pressure in the (dynamic) drainage area is derived for constant pressure and constant rate production scenarios. By deriving an explicit relation for average pressure in the drainage area as a function of the initial reservoir pressure and the wellbore pressure, the iterative procedure for calculation of pseudotime is relaxed. Using the developed expression for average pressure in the distance of investigation, the pseudo steady-state deliverability equation is extended to model the transient period by incorporating the dynamic drainage area concept in the productivity index equation. We first verify the applicability of the developed approach for oil reservoirs and later demonstrate that the approach is considered to be useful for analysis of production data from tight gas reservoirs.The established methodology in this work provides a useful tool for rapid forecasting of tight oil and tight gas wells, allowing for the examination of the effects of different parameters on the forecast.

Oil-gas reservoir lithofacies stochastic modeling based on one- to three-dimensional Markov chains

Stochastic modeling techniques have been widely applied to oil-gas reservoir lithofacies. Markov chain simulation, however, is still under development, mainly because of the difficulties in reasonably defining conditional probabilities for multi-dimensional Markov chains and determining transition probabilities for horizontal strike and dip directions. The aim of this work is to solve these problems. Firstly, the calculation formulae of conditional probabilities for multi-dimensional Markov chain models are proposed under the full independence and conditional independence assumptions. It is noted that multi-dimensional Markov models based on the conditional independence assumption are reasonable because these models avoid the small-class underestimation problem. Then, the methods for determining transition probabilities are given. The vertical transition probabilities are obtained by computing the transition frequencies from drilling data, while the horizontal transition probabilities are estimated by using well data and the elongation ratios according to Walther’s law. Finally, these models are used to simulate the reservoir lithofacies distribution of Tahe oilfield in China. The results show that the conditional independence method performs better than the full independence counterpart in maintaining the true percentage composition and reproducing lithofacies spatial features.

Spatial features of change of petrographic and reservoir properties of rocks of the Productive series (case study Guneshli field, South-Caspian basin)

In the paper on example of Guneshli field the South-Caspian basin the character of spatial changes of lithofacial parameters of the main oil-gas reservoir in Azerbaijan — productive series (Early Pliocene) has been considered. These studies were based on analysis of thin sections of different stratigraphic complexes of the productive series, the data of geophysical studies of the wells and as well as 3D geological modeling. Significant lithofacial changeability of productive series has been revealed both in section and in area that is explained by features of paleo-geographic conditions of sedimentation in early Pliocene and participation of various sources of feed of the basin with sediments. Dependence of initial yields of wells on spatial heterogeneity of permeability of reservoir rocks has also been established. It is established that spatial heterogeneity of lithofacial and reservoir properties of rocks controls their oil saturation and well productivity.

A geospatial case‐based reasoning model for oil–gas reservoir evaluation

AbstractDelineating the distribution of oil and natural gas resources is a prerequisite of exploitation. The delineation methods usually include conventional techniques of reservoir evaluation and mathematical models. The conventional reservoir evaluation results generally depend on the experts' knowledge and experience in the field. The mathematical methods mostly require accurate models to be proposed. Considering spatial relationships and characteristics of geological reservoir problems, including nonlinearity, complexity and uncertainty, a novel model called geospatial case‐based reasoning for oil–gas reservoir evaluation was proposed in this article. The key components of the new model, including: (1) the joint representation of spatial relationship and attribute features; (2) the model of spatial relationship and attribute similarity joint reasoning; and (3) the methods of establishing weights for the spatial relationship and attribute features, are completely constructed. A case study of the proposed model for gas reservoir evaluation was carried out. Compared with the backpropagation artificial neural network (BP‐ANN) and the geological empirical evaluation (GEE) methods, the model presented in this article performs 6.38% and 46.81% better than BP‐ANN and GEE, respectively. Furthermore, its execution is simpler, more convenient, and importantly, its utilization hardly requires any professional knowledge of the field.

Shear-induced permeability reduction and shear-zone development of sand under high vertical stress

To evaluate the permeability perpendicular to the shear zone with shear-zone development in silica sand under high vertical stress, we investigated the effects of shear displacement on permeability variation by performing a laboratory study involving ring-shear testing. The permeability changes under low and high vertical stresses were drastic and gradual, respectively, with increasing shear displacement. The shear-zone thickness under each set of stress and shear displacement conditions was determined by observing the particle crushing and compaction in the microstructure. The pore-diameter reductions were dependent on both the shear displacement and stress. The clear relations between the cumulative pore-diameter frequencies and median grain sizes in samples with shear zones were determined through the measured vertical stresses. In the grain-size analyses of the shear-zone samples, the reductions of the sand size fraction and median grain size with shear could reflect the shapes of the permeability variations in two distinct groups of shear and stress conditions in the tests. The correlations identified between the cumulative pore-diameter frequencies and median grain sizes in the shear-zone samples were obtained under vertical stresses. The results of this study are expected to enhance understanding of the permeability mechanisms in fault and slip zones in sandy sediments, enabling the estimation of permeability and groundwater movement in landslides as well as the development of preliminary simulations for production operations in oil and natural gas reservoirs.

A time fractional convection–diffusion equation to model gas transport through heterogeneous soil and gas reservoirs

Fractional-derivative models have been developed recently to interpret various hydrologic dynamics, such as dissolved contaminant transport in groundwater. However, they have not been applied to quantify other fluid dynamics, such as gas transport through complex geological media. This study reviewed previous gas transport experiments conducted in laboratory columns and real-world oil–gas reservoirs and found that gas dynamics exhibit typical sub-diffusive behavior characterized by heavy late-time tailing in the gas breakthrough curves (BTCs), which cannot be effectively captured by classical transport models. Numerical tests and field applications of the time fractional convection–diffusion equation (fCDE) have shown that the fCDE model can capture the observed gas BTCs including their apparent positive skewness. Sensitivity analysis further revealed that the three parameters used in the fCDE model, including the time index, the convection velocity, and the diffusion coefficient, play different roles in interpreting the delayed gas transport dynamics. In addition, the model comparison and analysis showed that the time fCDE model is efficient in application. Therefore, the time fractional-derivative models can be conveniently extended to quantify gas transport through natural geological media such as complex oil–gas reservoirs.

Screening and ranking framework for underground hydrogen storage site selection in Poland

This paper proposes the use of the Analytic Hierarchy Process (AHP) in order to select the potential underground hydrogen storage sites. The preliminary selection and evaluation of hydrogen storage sites may be considered as a multi-criteria decision-making process. The use of a decision model based on 5 (for aquifers) or 6 geological criteria (in the case of salt and hydrocarbon deposits) has been proposed. A ranking of salt structures, aquifers, and crude oil and natural gas reservoirs, previously identified as the potential hydrogen storage sites in Poland, has been presented. The obtained results have confirmed that the AHP-based approach can be useful for preliminary selection of potential underground hydrogen storage sites. The proposed method enables one to objectively choose the most satisfactory decision, from the point of view of the adopted decision-making criteria, regarding the choice of the best structure.

Investigating Multiphase Flow Phenomena in Fine-Grained Reservoir Rocks: Insights from Using Ethane Permeability Measurements over a Range of Pore Pressures

The ability to quantify effective permeability at the various fluid saturations and stress states experienced during production from shale oil and shale gas reservoirs is required for efficient exploitation of the resources, but to date experimental challenges prevent measurement of the effective permeability of these materials over a range of fluid saturations. To work towards overcoming these challenges, we measured effective permeability of a suite of gas shales to gaseous ethane over a range of pore pressures up to the saturated vapour pressure. Liquid/semiliquid ethane saturation increases due to adsorption and capillary condensation with increasing pore pressure resulting in decreasing effective permeability to ethane gas. By how much effective permeability to ethane gas decreases with adsorption and capillary condensation depends on the pore size distribution of each sample and the stress state that effective permeability is measured at. Effective permeability decreases more at higher stress states because the pores are smaller at higher stress states. The largest effective permeability drops occur in samples with dominant pore sizes in the mesopore range. These pores are completely blocked due to capillary condensation at pore pressures near the saturated vapour pressure of ethane. Blockage of these pores cuts off the main fluid flow pathways in the rock, thereby drastically decreasing effective permeability to ethane gas.

Forecast on Water Locking Damage of Low Permeable Reservoir with Quantum Neural Network

It is of great importance in oil-gas reservoir protection to timely and correctly forecast the water locking damage, the greatest damage for low permeable reservoir. An analysis is conducted on the production mechanism and various influence factors of water locking damage, based on which a quantum neuron is constructed based on the information processing manner of a biological neuron and the principle of quantum neural algorithm, besides, the quantum neural network model forecasting the water locking of the reservoir is established and related software is also made to forecast the water locking damage of the gas reservoir. This method has overcome the defects of grey correlation analysis that requires evaluation matrix analysis and complicated operation. According to the practice in Longxi Area of Daqing Oilfield, this method is characterized by fast operation, few system parameters and high accuracy rate (the general incidence rate may reach 90%), which can provide reliable support for the protection technique of low permeable reservoir.

Geologic-seismic models, prediction of shallow-water lacustrine delta sandbody and hydrocarbon potential in the Late Miocene, Huanghekou Sag, Bohai Bay Basin, northern China

The Huanghekou Sag is located at the southeast part of the Bohai Bay Basin, northern China. Large-scale shallow lake delta developed in the Neogene provided suitable geological conditions for the formation of a subtle oil-gas reservoir in this area. The key for analyzing sandstone reservoir and sedimentary facies is by using seismic attributes (amplitude) to establish the relationship between lithology combination and seismic attributes. The lower unit of Late Miocene Minghuazhen Formation at the BZ34 block in the Huanghekou Sag was subdivided into 10 parasequence sets (PSS). Thicker sandstones mainly occurred in PSS1 and PSS10, whereas thin sandstones are mostly observed within other parasequence sets. This study presents statistics and analyses of lithology, i.e., statistics of root-mean-square (RMS) amplitude and lithology of well locations in different parasequence sets of the study area, as well as 1-D forward seismic models of 7 types of lithology combinations, the establishment of a spatial distribution of 2-D sandbody, forward seismic models etc. Our study indicates that high amplitude peaks correspond to thicker sandbodies, while low amplitude indicates non-development of sandbodies (generally less than 2 m), and medium amplitude agrees well with large sets of mudstones interbedded with medium and thinner sandstones. Different sand–mudstone combinations genetically reflect a combination of multiple micro-facies, therefore, amplitude features can predict sandbodies as well as facies characteristics.

Experimental study on the application of an ionic liquid as a shale inhibitor and inhibitive mechanism

Wellbore instability is caused to a great degree by shale hydration, which results from the interaction between the exposed shale formation and water-based drilling fluids in the exploration of oil and natural gas reservoirs. In this paper, an ionic liquid (ILB) is utilized as an efficient shale inhibitor in water-based drilling fluids to minimize shale hydration. The inhibitive property of ILB is evaluated by hot-rolling dispersion, capillary suction time and bentonite swelling tests. The test results indicate that 0.05wt% ILB exhibits superior inhibition performance than 5wt% conventional inhibitor potassium chloride (KCl) and its inhibition effect is approximately equal to that of 2wt% polyether diamine (PA). But different from KCl and PA, the presence of low concentration of ILB can also improve the rheological properties of water-based drilling fluids at high temperature, and meanwhile has no adverse effect on their filtration property. The investigation of inhibition mechanism indicates that the thermal stability of Na-Mt is greatly improved due to the intercalation with cationic group of ILB, leading to excellent inhibition property of ILB at high temperature. Furthermore, the adsorption of ILB in the interlayer of Na-Mt weakens the hydrophilicity of Na-Mt, which further inhibits water ingress.

Effect of foam quality on flow behavior of liquid CO2-based foam fracturing fluid stabilized by hydrofluoroether

Hydrofluoroether C4F9OCH3, as a foaming agent in liquid CO2, is used to stabilize bubble in liquid CO2-based foam fracturing fluid which is waterless and no damage to oil-gas reservoir. However, characteristics of this environmental friendly CO2-based foam, such as the foam morphology and its flow behaviors in pipe, are insufficiently understood. Especially, foam quality, one of important characteristic parameters in a foam fluid, has significant effects on foam structure and flow behaviors of CO2-based foam. By means of the flow tests in pipes with different diameters, it was found that the CO2-based foam displayed wall slip phenomenon, and Oldroyd-Jastrzebski method was used to deal with this phenomenon. Effective viscosity of this CO2-based foam, as well as convective heat transfer coefficient initially increases and then decreases with the increase of foam quality. Due to dominant collision and friction among bubbles, their values reach the corresponding maximums when the foam quality is about 0.82. Meanwhile, the evolution of rheological parameters of CO2-based foam with the foam quality is shown as well, and the exponential relationship between yield stress and foam quality is illustrated. Additionally, as for the flow friction characteristics, it shows that fanning friction factor increases and drag reduction rate initially increases and then decreases as the foam quality is increased.

Early Paleozoic Tarim Orocline: Insights from paleogeography and tectonic evolution in the Tarim Basin

The Tarim Basin, situated between the Paleo‐Asian tectonic domain and the Proto‐Tethys tectonic domain, has undergone a complex tectonic evolutionary process under various geodynamic conditions and has provided abundant information about the dynamic evolution of the peripheral orogens. From the Sinian to Early Ordovician, the Tarim–Qaidam Block was under a regional extensional setting. A carbonate platform developed widely in the basin, flanked by a passive continental margin setting. As the extension enhanced, the spreading of the Proto‐Tethys Ocean was accompanied by subduction and collision, which resulted in a nearly linear subduction zone. Since the Late Cambrian, a continuous oblique subduction and induced sinistral shearing produced an initial bending of the Proto‐Tethys subduction zone, leading to rotation and bend of the original Tarim–Qaidam Block and internal long striped subaqueous paleo‐uplift. During the Middle and Late Ordovician, the Altyn–Qilian Orogen underwent continent–continent collision and continental crust deep subduction. The buckling of the subduction system enhanced under the sinistral transpressional field, resulted in the bending of the Altyn–Qilian Orogen to an S‐shape. The subaqueous uplift areas in the basin were further elevated, rotated, and eroded to show an S‐shape distribution and an unconformity developed between the Silurian sediments and underlying strata. The extent of the carbonate platform decreased, around which developed a high‐energy facies in a platform margin and formed important oil–gas reservoirs. In the Silurian to Middle Devonian, the Tarim Basin evolved into a “two uplifts with a depression” framework under the dual‐directional compressional field. Near the end of the Late Devonian, the S‐shape distribution pattern of paleo‐uplifts was covered by the Upper Devonian and Carboniferous sequence in an angular unconformity. Moreover, the planar distribution of thrust faults with strike‐slip property around the paleo‐uplifts also showed an S‐shape. Accompanying small‐scale strike‐slip faults presented as the radial axial cleavages of plunging vertical folds around a vertical hinge, which indicated that the pre‐existing thrust faults bent around a vertical axis resulting from late strike‐slip faults, demonstrating a coupling between the Tarim Basin and orocline of the Early Paleozoic orogens in the Proto‐Tethys Ocean, called the Tarim Orocline.

Formation of a giant Zn–Pb deposit from hot brines injecting into a shallow oil–gas reservoir in sandstones, Jinding, southwestern China

AbstractThe association between mineralisation and hydrocarbons in sedimentary basins is widely recognised, but the nature and significance of their relationships are not fully understood. This paper provides an example of metalliferous brines injecting into a palaeo‐oil–gas reservoir to form a world‐class Zn–Pb deposit (Jinding, China). Petrographic and microthermometric studies of oil inclusions and PVT simulations suggest that oil and gas were charged in a shallow (<1300 m) environment before mineralisation. This environment favoured bacterial sulphate reduction (BSR), which produced large amounts of H2S that accumulated in the gas cap. Forceful injection of hot brines penetrated the oil zone to reach the H2S‐rich gas cap and precipitated sulphide ores. Individual fluid injection events were short‐lived, and the reservoir was only partly and briefly heated to beyond the bacterial survival temperature. Episodic injection of metalliferous brines and sustained supply of H2S through BSR resulted in the formation of a large Zn–Pb deposit.

Offshore CO2 Storage Resource Assessment of the Northern Gulf of Mexico

Research programs recognize the need to further develop offshore storage resources for successful global deployment of CCUS. The inner continental shelf of the northwestern Gulf of Mexico is especially prospective because it has abundant available geologic data accumulated from decades of hydrocarbon exploration near many large point sources of industrial CO2. An ongoing study on the upper Texas coast to Vermilion Bay (western Louisiana) assesses prospective geologic storage resources for the approximately 8,000 square mile study area. The study, encompassing state and federal waters, utilizes 1) existing rock samples (e.g., whole cores), 2) well logs, and other data from existing or P&A wells and 3) available 2D, a convention regional 3D and a high resolution 3D seismic surveys to assess storage resources (e.g., faults, reservoir and seal units, etc.). The study utilizes the available geologic data resources to 1) assess the CO2 storage capacity of depleted oil and natural gas reservoirs, and 2) assess the ability of saline formations in the region to safely and permanently store nationally-significant amounts of anthropogenic CO2. The study also seeks to identify at least one specific site with potential to store at least 30 million metric tons of CO2 that could be further considered in the future for a commercial or integrated demonstration project.