Tight Sand Research Articles

Identification of Water-Flooded Layers and Evaluation of Flooded Levels in Fractured Tight Sand Oil Reservoir

Identification of Water-Flooded Layers and Evaluation of Flooded Levels in Fractured Tight Sand Oil Reservoir

Study on the fluidity of the pore-fracture binary system in a tight sandstone reservoir-NMR

Fluid movability in tight sands may not be accurately characterized by pore size-based classification methods solely because of the complex pore structure and heterogeneity in pore size. In this study, on the basis of casting thin slices and scanning electron microscope observation, pore structure was analyzed using mercury injection, NMR, and micron CT to classify and evaluate the tight oil reservoir. The experiment suggest that the quality of tight reservoir is determined by its pore structure, particularly the throat radius, with the microthroat being an essential factor in permeability. Uniquely, we divide the reservoir by Q-cluster with throat radius, displacement pressure, permeability and other parameters. Based on reservoir classification, this study proposed a method for studying the pore size classification of samples on the T2 spectrum by combining CT scanning with mercury intrusion and a NMR experiment. Pore fluids are generally classified into movable fluid and irreducible fluid by one or two NMR T2 cut-offs. The pore size distributions and capillarity boundaries are converted from T2 and mercury injection capillary pressure (MICP). We categorized pores into micropores (T2 < 1), macropores (T2 > 10, with T2 > 300 as fractures), and medium pores (the rest). The saturation of movable fluid and the percentage of micro-fractures can characterize the seepage characteristics of tight reservoirs, which is of great significance for the later periods of oilfield development.

Prediction of tight sandstone reservoirs by multiwave joint prestack inversion technology: A case study of the Qiulin area in the Sichuan Basin

The Shaximiao (SXM) Formation of the Middle Triassic in the central Sichuan Basin is a river-lake sedimentary system with an average burial depth of 2800 m. The channel sand bodies of the SXM Formation in the Qiulin area are developed with large lateral variation and high- and medium-porosity sand. This leads to great differences in the seismic response and difficulty in predicting the sand bodies and reservoirs using P-wave data. We carry out well-log analysis for different types of sand bodies. The no. 8 sand body of high porosity can be effectively identified using P-wave impedance (PI). Whereas for the no. 7 sand body of relatively lower porosity (mainly due to the higher shale content in the no. 7 sand compared with the no. 8 sand), sandstone and mudstone can be distinguished using S-wave impedance (SI), and reservoirs can be recognized by the P- to S-wave velocity ratio ([Formula: see text]/[Formula: see text]). Based on the PP wave and the P-to-S converted wave (PS wave) (after matching) angle-stacked data, a prestack inversion of multicomponent data is performed. Multiwave joint inversion results (SI and [Formula: see text]/[Formula: see text]) have better accuracy and stronger stability than the PP-wave inversion in practical application. In addition, the PI of the joint inversion more clearly describes the distribution and boundaries of the channel sand and better matches the prediction and drilling data in sand 8. The SI of the joint inversion can identify subtle sand bodies (weak PI contrast) that are difficult to be detected by PP-wave inversion. The distribution of the reservoir predicted by the [Formula: see text]/[Formula: see text] of the joint inversion is clearer (the no. 7 sand body) and better than that by the PP-wave inversion. This study demonstrates the advantage of the multiwave joint inversion technology in tight sand identification.

Integrated Technique Provides Effective Water Diagnostics in Tight Sand

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper URTeC 3864145, “Evaluating the Hydraulic Fracture Through Acoustic Reflection Imaging and Production Logging for Water Diagnostic Beyond the Wellbore: A Case Study From Chang 8 Tight Sand in the Ordos Basin, China,” by Guangsheng Liu, Dajian Li, and Gang Zheng, PetroChina, et al. The paper has not been peer reviewed. _ The Triassic Chang 8 tight sand reservoir in the Xifeng block of the Ordos Basin features low permeability, which means that hydraulic fracturing and subsequent waterflooding were performed during its development phase. Water breakthrough was encountered after a short period of oil production. A solution of borehole acoustic reflection imaging combined with production logging was proposed in a horizontal well suffering from high water cut. The objective was to determine which stages contributed most to water production, understand the cause, and, ultimately, create a water shutoff plan. Introduction The Ordos Basin, with an area of approximately 2.5×105 km2, is in North China. The Upper Triassic Yanchang formation is subdivided into the Chang 1 to 10 members, from top to bottom. It contains significant oil reserves in siltstone and sandstone reservoirs, especially in Chang 6 through Chang 8, that have been the major oil-producing resources in recent years. In the Triassic Chang 8 tight sand reservoir, horizontal well drilling and multiple-stage hydraulic fracturing have become common practice. In the study block, the well of interest was hydraulically fractured by coiled tubing with sand-jet perforation and fracturing operations in one run with a retrievable packer in the bottomhole assembly of the coiled tubing. In the study block, when some producing wells encountered water breakthrough, traditional water diagnostics using production logging was not enough; a survey to detect hydraulic fractures beyond the wellbore was needed. Theory and Methods Borehole Acoustic Reflection Imaging. The processing workflow for acoustic reflected waves mainly consists of two parts. The first is a filtering process to suppress the borehole mode and noise in order to preserve the reflected wave. The second is to migrate the reflected wave to the true position of a reflector. The conventional migration method used for acoustic reflection imaging normally requests previous information relating to reflector dip and produces 2D images, which show the reflector shape but have hard-to-extract precise quantitative information. A trial reflector-migration method covered in the literature was introduced in 2016 that does not require input of structure dip and is of high resolution. A 3D slowness-time-coherence method was developed in 2018, also covered in the literature, that could determine the true dip, azimuth, and distance of a reflector.

Pressure Transient and Production Analysis of Fractured Vertical Wells in Tight Sand Gas Reservoirs Considering Threshold Pressure Gradient, Phase-Change Phenomenon, and Stress Sensitivity

The productivity and pressure response of the tight sand gas wells are influenced by multiple flow mechanisms, such as threshold pressure gradient, phase-change phenomena, and stress sensitivity. Understanding the sensitivity of these factors is crucial for the effective development of tight sand gas reservoirs. This study aims to clarify the sensitivity of various factors affecting the productivity and pressure response of tight sand gas wells. Based on the percolation theory of tight sand gas reservoirs, we considered stress sensitivity, threshold pressure gradient, and phase-change phenomena to derive an unsteady mathematical model of a fractured well with an infinite boundary, and a point source solution was obtained. The proposed model was solved using series function properties, variable substitution, perturbation technique, Poisson superposition formula, Laplace transform, and numerical inversion. The influence of several important parameters on pressure response and productivity is discussed in detail. The results show that the threshold pressure gradient, stress sensitivity, and skin factor significantly impact gas well production and pressure response, while the wellbore storage effect and phase-change effect primarily affect the initial production and pressure response, having little effect on the cumulative gas production. The proposed model can estimate the influence of the threshold pressure gradient and stress sensitivity on productivity and pressure, providing a guide for the development of technical measures for fractured wells in tight sand gas reservoirs.

Reservoir rock typing assessment in a coal-tight sand based heterogeneous geological formation through advanced AI methods

Geoscientists now identify coal layers using conventional well logs. Coal layer identification is the main technical difficulty in coalbed methane exploration and development. This research uses advanced quantile–quantile plot, self-organizing maps (SOM), k-means clustering, t-distributed stochastic neighbor embedding (t-SNE) and qualitative log curve assessment through three wells (X4, X5, X6) in complex geological formation to distinguish coal from tight sand and shale. Also, we identify the reservoir rock typing (RRT), gas-bearing and non-gas bearing potential zones. Results showed gamma-ray and resistivity logs are not reliable tools for coal identification. Further, coal layers highlighted high acoustic (AC) and neutron porosity (CNL), low density (DEN), low photoelectric, and low porosity values as compared to tight sand and shale. While, tight sand highlighted 5–10% porosity values. The SOM and clustering assessment provided the evidence of good-quality RRT for tight sand facies, whereas other clusters related to shale and coal showed poor-quality RRT. A t-SNE algorithm accurately distinguished coal and was used to make CNL and DEN plot that showed the presence of low-rank bituminous coal rank in study area. The presented strategy through conventional logs shall provide help to comprehend coal-tight sand lithofacies units for future mining.

Phase envelopes in reservoir fill analysis: Two contrasting scenarios

Phase envelopes are routinely employed by reservoir engineers for fluid characterisation. These envelopes are controlled by reservoir fluid composition, pressure and temperature. As a result of increasing source-rock maturation, fluids with decreasing molecular weights and densities and increasing gas-to-oil ratios (and hence different phase envelopes) are generated, which are thus linked to fluid history. In addition to their importance for exploration, charge models can play a key role in constraining reservoir models and optimising field development, particularly when pressure–volume-temperature (PVT) data are properly integrated with fluid geochemistry. Two contrasting scenarios of fluid phase evolution from two different fields are presented, and their relations to charge analysis and reservoir models are discussed. The first example discusses the identification, based on hydrocarbon geochemistry complemented by overlapping modeled phase envelopes, of compartmentalised filling cycles in what was initially considered a single oil-rimmed gas accumulation. The second example presents an opposite scenario where two wet gas accumulations 20-km apart laterally and 400-feet average depth difference appear to represent a single more-expansive accumulation spread over areas of variable PVT conditions and reservoir qualities. The wet gas across both accumulations is characterised by a continuous phase evolution pattern that shrinks systematically (cricondentherm shifts to lower temperature and cricondenbar to lower pressure), suggestive of phase fractionation of a charge of single maturity. The proposed gas distribution model represents a discovery of a hybrid conventional and unconventional (tight sand) system, with potential for basin-centered gas. These findings provided better understanding of observed and projected fluids, impacting the development and completion plans by locating new gas producers. A recent well drilled midway between the two accumulations indeed tested wet gas, confirming fluid connectivity. Future work will attempt to link the gas distribution model with seismic attributes.

Linearized waveform inversion for vertical transversely isotropic elastic media: Methodology and multi-parameter crosstalk analysis

Seismic migration and inversion are closely related techniques to portray subsurface images and identify hydrocarbon reservoirs. Seismic migration aims at obtaining structural images of subsurface geologic discontinuities. More specifically, seismic migration estimates the reflectivity function (stacked average reflectivity or pre-stack angle-dependent reflectivity) from seismic reflection data. On the other hand, seismic inversion quantitatively estimates the intrinsic rock properties of subsurface formulations. Such seismic inversion methods are applicable to detect hydrocarbon reservoirs that may exhibit lateral variations in the inverted parameters. Although there exist many differences, pre-stack seismic migration is similar with the first iteration of the general linearized seismic inversion.Usually, seismic migration and inversion techniques assume an acoustic or isotropic elastic medium. Unconventional reservoirs such as shale and tight sand formation have notable anisotropic property. We present a linearized waveform inversion (LWI) scheme for weakly anisotropic elastic media with vertical transversely isotropic (VTI) symmetry. It is based on two-way anisotropic elastic wave equation and simultaneously inverts for the localized perturbations (ΔVp0/Vp0,ΔVs0/Vs0,Δϵ,Δδ) from the long-wavelength reference model. Our proposed VTI-elastic LWI is an iterative method that requires a forward and an adjoint operator acting on vectors in each iteration. We derive the forward Born approximation operator by perturbation theory and adjoint operator via adjoint-state method. The inversion has improved the quality of the images and reduces the multi-parameter crosstalk comparing with the adjoint-based images. We have observed that the multi-parameter crosstalk problem is more prominent in the inversion images for Thomsen anisotropy parameters. Especially, the Thomsen parameter δ is the most difficult to resolve. We also analyze the multi-parameter crosstalk using scattering radiation patterns.The linearized waveform inversion for VTI-elastic media presented in this article provides quantitative information of the rock properties that has the potential to help identify hydrocarbon reservoirs.

Effects of Drilling Number and Distribution on Fracture Using the Pulse Plasma on Tight Sand Reservoir

Summary The permeability of unconventional reservoirs is extremely low, resulting in their drainage area being limited to tens of feet. Therefore, researchers have developed an effective stimulation technology that can be used in combination with conventional hydraulic fracturing, namely, pulsed plasma fracturing technology. Pulsed plasma fracturing technology is an efficient and environmentally friendly auxiliary hydraulic fracturing stimulation technology. However, most existing studies have focused only on the effect of pulsed plasma fracturing on single wells, ignoring the effect of the number and distribution of wells drilled on pulsed plasma fracturing. In this paper, pulsed plasma fracturing is studied by a self-built pulsed plasma experimental platform and nonlinear finite element software. First, the generation and propagation mechanism of shock wave, fracture type, and stress field analysis of rock mass in pulsed plasma fracturing technology are discussed. The double-well experiment was carried out by using the experimental platform, and the fracture law of fractures under different wellhead distribution conditions was obtained. In addition, a multiwell mathematical model is established by using the combination of the Euler method and Lagrange method to simulate the interaction between fluid and solid, that is, arbitrary Lagrangian Eulerian (ALE) multimaterial fluid-solid coupling method and the influence of drilling times and wellhead distribution on pulsed plasma fracturing is discussed. Stress analysis shows that the rock is mainly affected by ground stress, liquid column pressure, and shock wave pressure. The experimental results show that the discharge voltage is positively correlated with the shock wave pressure on the rock. The distribution of different wellheads affects the distribution and length of fractures. The double-well experiment makes the fractures easier to fracture. The simulation results show that the fracture length in the connection direction of the two wells is longer, and the fracture length in the vertical direction is shorter. This shows that the number and distribution of drilling affect the initiation and propagation of fractures.

A case study of petrophysical prediction using machine learning integrated with interval inversion in a tight sand reservoir in Egypt

This study presents a new algorithm for reservoir characterization using borehole logging data, which integrates unsupervised machine learning techniques and interval inversion to automatically determine layers’ boundaries and petrophysical parameters. The research aims to reduce the time and manual input required for borehole inversion to estimate petrophysical parameters. The algorithm was used to predict different layer boundaries of sand-shale intercalations for both synthetic and field wireline log data. Field well logging measurements were obtained from an oil and gas field in Egypt, specifically the Jurassic reservoir. The reservoir is composed of a dense sandstone layer with significant heterogeneity due to diagenesis, which converts kaolinite into illite. The algorithm was used to predict petrophysical parameters, resulting in a decrease in porosity and permeability. The field data from the well reveals that the reservoir is made up of varying-quality sandstone, impacting storage capacity and hydrocarbon saturation. The algorithm demonstrates consistent convergence of the data at 7.5%. Overall, the integration of the new cluster technique and interval inversion can improve the time-intensive and laborious process of borehole data inversion to estimate petrophysical parameters.

Blasingame production decline curve analysis for fractured tight sand gas wells based on embedded discrete fracture model

Blasingame production decline curve analysis (PDCA) is crucial for extracting natural gas from fractured tight sandstone reservoirs (FTSRs). The natural gas flow in FTSRs is complex due to high-velocity non-Darcy (hvnD) flow, threshold pressure gradient (TPG), and stress sensitivity of reservoirs. These factors pose a challenge in solving nonlinear equations. In this paper, we establish a mathematical model for the flow of natural gas in FTSRs. The fracture is characterized by a hvnD flow coupled using an embedded discrete fracture model (EDFM). The gas flow in the matrix is coupled with the TPG. Stress sensitivity has been considered in both fractures and matrix. The finite volume method (FVM) was employed to discretize and solve the nonlinear equations in the model. The pressure-normalized rate algorithm and gas flow model were used to present a Blasingame production decline curve for fractured horizontal wells in FTSRs. The Blasingame production decline curve can be used to identify natural gas flow regimes, matrix petrophysical properties, and fracture parameters. The effect of the hvnD flow in fractures, the lvnD flow in the matrix (TPG), stress sensitivity, fracture parameters, and production schedule on the Blasingame production decline curve and pressure profile are discussed in detail. This study provides scientific and theoretical support for predicting gas wells performance and the gas production decline law in FTSRs.

Unconventional Reservoir Characterization and Formation Evaluation: A Case Study of a Tight Sandstone Reservoir in West Africa

Unconventional reservoirs, including gas shales and tight gas sands, have gained prominence in the energy sector due to technological advancements and escalating energy demands. The oil industry is eagerly refining techniques to decipher these reservoirs, aiming to reduce data collection costs and uncertainties in reserve estimations. Characteristically, tight reservoirs exhibit low matrix porosity and ultra-low permeability, necessitating artificial stimulation for enhanced production. The efficacy of the stimulation hinges on the organic material distribution, the rock’s mechanical attributes, and the prevailing stress field. Comprehensive petrophysical analysis, integrating standard and specialized logs, core analyses, and dynamic data, is pivotal for a nuanced understanding of these reservoirs. This ensures a reduction in prediction uncertainties, with parameters like shale volume, porosity, and permeability being vital. This article delves into an intricate petrophysical evaluation of the Nene field, a West African unconventional reservoir. It underscores the geological intricacies of the field, the pivotal role of data acquisition, and introduces avant-garde methodologies for depth matching, rock typing, and the estimation of permeability. This research highlights the significance of unconventional reservoir exploration in today’s energy milieu, offering a granular understanding of the Nene field’s geological challenges and proffering a blueprint for analogous future endeavours in unconventional reservoirs.

Petroleum geology of conventional and unconventional resources: Introduction

Understanding reservoir, source, seal, migration pathways and trap characterization is the first step towards better energy resource exploitation. Several studies have been conducted in recent decades on the reservoir characteristics of conventional resources. Unconventional resources, on the other hand, have received more attention as alternative future energy solutions to depleted conventional resources. Drilling, exploration, development, and production of conventional and unconventional resources pose technical challenges to the energy industry. This special issue attempts to address the most pressing technical challenges in developing conventional reservoirs (such as sandstone and carbonate reservoirs) as well as unconventional energy sources (e.g., shale gas, shale oil, tight gas sand, coal bed methane, geothermal and gas hydrates). The special issue is composed of 21 papers that are classified into six different groups related to the physical and mechanical properties of reservoirs, petroleum geochemistry, petroleum geology, geological modelling, unconventional resource evaluation and conventional reservoir evaluation.

Seepage Model and Pressure Response Characteristics of Non-Orthogonal Multi-Fracture Vertical Wells with Superimposed Sand Body in Tight Gas Reservoirs

Faced with difficulties stemming from the complex interactions between tight gas sand bodies and fractures, when describing and identifying reservoirs, a composite reservoir model was established. By setting the supply boundary to characterize the superposition characteristics of sand bodies, a mathematical model of unstable seepage in fractured vertical wells in tight sandstone gas reservoirs was developed, considering factors such as stress sensitivity, fracture density and fracture symmetry. The seepage law and pressure response characteristics of gas wells in tight sandstone discontinuous reservoirs with stress sensitivity, semi-permeable supply boundary and complex fracture topology were determined, and the reliability of the model was verified. The research results more accurately display the pressure characteristic of a vertical well in the superimposed sand body with complex fractures and provide a more comprehensive model for tight gas production dynamic analysis and well test data analysis, which can more accurately guide the dynamic inversion of reservoir and fracture parameters.

Statistical and machine learning hybridization for predicting shear wave velocity in tight sand reservoirs: A case study

Shear wave velocity plays an important role in describing the reservoir's petrophysical and geomechanical characteristics. It is also important to understand the mechanical behavior of the reservoir since it is closely related to rock strength and stiffness. However, it is rarely logged due to the high acquisition cost. Geoscientists have developed a variety of methods for predicting shear wave velocities, including linear regression and neural networks. However, none of these statistical approaches have been combined with unsupervised learning to evaluate the model's efficacy. Most of the multivariate correlations reported in the literature for shear wave prediction in the tight sand reservoirs did not account for the multicollinearity effect of the VP-VS correlation, which may result in overfitting of the model. Considering these factors, we utilized wireline logs to model multivariate linear and non-linear regression using k-means squares-based electrofacies (EF). We further converted them into EF-constrained supervised learning models. A multicollinearity effect was assessed in linear regression models to observe the need for ridge regression. The results indicate that EF-constrained statistical models and adaptive neuro-fuzzy inference system (ANFIS) models enhanced accuracy in predicting shear velocity. However, the multivariate non-linear regression analysis predicted the shear velocity more accurately than the multivariate linear regression analysis. The absence of data points within the EF1 has an adverse effect on the accuracy of all statistical and ANFIS models. The results of this study will help to understand the impact of lithological EF on estimating shear wave velocity using multivariate linear regression, multivariate non-linear regression, and ANFIS.

Experimental and EOR Mechanism Study of Water Shutoff Effects on Fractured Tight Sand Gas Reservoirs Using Fuzzy Ball Fluids

In recent years, there has been quite a dispute over the water shutoff effect of fuzzy ball fluids in fractured tight sandstone gas reservoirs. The core issue of this dispute is to try and make fuzzy ball fluid stabilize gas during the water shutoff process for sustainable development. In order to solve this dispute, the Linxing He-2 reservoir matrix core and a core with artificial fractures were used to simulate interlayer water, artificial fractures, and water output channels from the side and bottom. Simulated formation water and nitrogen were used as the two-phase flow phase. The breakthrough pressure of the air and water phases was tested after plugging with fuzzy ball fluid in order to simulate and analyze the water shutoff effect of the fuzzy ball fluid and its ability to achieve air establishment and water control. The results of this study show that for the core matrix, the breakthrough pressure gradient for water and gas varied from 0.200 MPa/cm to 0.210 MPa/cm and 0.015 MPa/cm to 0.025 MPa/cm, and for artificial fractured cores, the breakthrough pressure gradient of water and gas varied from 0.035 MPa/cm to 0.040 MPa/cm and 0.015 MPa/cm to 0.020 MPa/cm. These results prove that fuzzy ball fluid can block small-scale water output channels, such as matrix pores, through the polymer film-forming structure, and plug the artistic cracks and large-scale water output channels of the water flowing into the sides and bottom through the accumulation of a large number of fuzzy balls, which greatly improves the flow resistance of water. The amount of fuzzy ball fluid should be carefully adjusted with consideration of the water output and formation conditions. For large-scale water output channels and side and bottom water shutoff operations, it is recommended that the amount of fuzzy balls be increased along with the number of fuzzy balls in the system in order to increase the breakthrough pressure of water and achieve the stable control of air and water. It is believed that the fuzzy balls would quickly change their shapes to match the sizes of fracture channels to enter into fractured reservoirs and that an active hydrophobic membrane would form on the surface of fractured rocks, with macromolecules and surfactants being dispersed in the fluid system. In addition, the interface between the fuzzy balls is also hydrophobic, which would slow down the flow of water and provide a continuous gas percolating channel after aggregating and entering into the fractures. This increases the persistence of water intruding into the formation and does not affect the percolation of the gas of fractured tight sandstone gas reservoirs. This research is of great significance for the EOR of tight sand gas reservoirs and the sustainable development of oil and gas resources in China.

Horizontal well path design with seismic inversion for a shale oil reservoir in the Ordos Basin, China

The Ordos Basin is located in the western part of the North-China Platform, where China’s largest shale oil field was discovered. Most of the production originates from relatively thin and tight sand bodies within the Chang 7 member of the Triassic Yanchang Formation. This consequently requires accurate and high-resolution inversion data to characterize the reservoirs and define the horizontal well paths. In this paper, we adopt full-waveform inversion (FWI) to obtain the velocity model for time-to-depth inversion. Compared with conventional migration velocity analysis, FWI can produce velocity models with more high-wavenumber variations that reflect thin and localized geologic features. Geologic statistical inversion is also applied to resolve the thin beds beyond seismic resolution. A comprehensive index is then computed with the inverted parameters to evaluate the reservoir and build a sweet-spot map. We define the coordinates, direction, and length of the horizontal well on the maps. The well path is subsequently carefully designed on the sections of the time-to-depth converted inversion data. The effectiveness of the workflow is verified using the application case of the Qingcheng oil field at the Ordos Basin.

Micropore Throat Structure and Movable Fluid Characteristics of Chang 63 Tight Sandstone in Baibao Area of Ordos Basin

Tight sand is an important unconventional reservoir. Aiming at the problem of large unused reserves and the poor development effect of Chang 63 reservoir, this paper researches reunderstanding reservoir and evaluating unused reserves. Employing rock slice and scanning electron microscope (SEM), the experiment of low-field nuclear magnetic resonance (NMR), water-oil relative permeability experiment, reservoir space, movable fluid, and oil-water seepage characteristics was studied. The factors affecting NMR T 2 cutoff, controlling factors of movable fluids, and controlling factors of displacing efficiency in tight sandstone reservoirs are discussed. The study demonstrates that (1) the mean pore volume and permeability are 4.4% and 0.068 mD, respectively. The reservoir pertains to tight sandstone, mainly intergranular pore and dissolution pore, and the intercalated materials are mainly chlorite and illite. (2) The characteristic of the NMR T 2 spectrum has bimodal characteristics and can be subdivided into two classes: left peak dominant and right peak dominant. The mean value of mobile fluid saturation was 17.9%. (3) According to the relative permeability curve pattern, it is divided into four categories, and the mean bound water saturation is 29.9%. The average irreducible oil saturation was 40.6%. The mean oil flooding efficiency was 40.2%. (4) The better the pore-throat relationship, the lower the T 2 cutoff, the stronger ability of the fluid migration ability, and the higher of a percentage of active fluid. The percentage of active fluid in a low-permeability reservoir is affected by the reservoir’s physical property and pore structure.

Pressure transient analysis for multi-stage fractured horizontal wells considering threshold pressure gradient and stress sensitivity in tight sandstone gas reservoirs

Tight sand gas reservoirs are characterized with low porosity and low permeability. The threshold pressure gradient (TPG) and stress sensitivity effect are particularly apparent during gas production in tight sand gas reservoirs, causing the pressure transient analysis (PTA) curves of multi-stage fracturing horizontal wells (MFHWs) in tight sand gas reservoirs to be abnormally upward and making it challenging to match current PTA models. Therefore, in this work, a new PTA model for MFHW considering TPG and stress sensitivity was established. Based on the point source function, a semi-analytical solution of the model could be obtained using the properties of series function, variable substitution, perturbation technique, Poisson superposition formula, Laplace transform, and numerical inversion. Moreover, the effects of TPG, stress sensitivity, well parameters, and fracture parameters on the PTA curves were analyzed. Overall, we believe that the results of this study can guide the pressure transient analysis of MFHWs in tight sand gas reservoirs and provide help for engineers with regard to evaluating the parameters of reservoirs and fractures more accurately.

Optimized rock physics model implementation to characterize the heterogeneous B-interval reservoir facies in the petro-elastic domain, mubarak block, lower indus basin, Pakistan

Rock physics abridges geological and reservoir parameters to quantify the heterogeneous hydrocarbon reservoir facies in the petro-elastic domain. The widely distributed Lower Goru sands across the Lower Indus Basin are proven hydrocarbon reservoirs and exhibit heterogeneity due to their complex depositional environment. Diagenetic detrital quartz overgrowth cementation, sand, shale intercalation, and various fluids add more challenges to characterize facies in the petro-elastic domain. For precise petro-elastic relationship establishment, an extended cemented sandstone rock physics model for B-Interval sands of the Lower Goru Formation was developed. It produced conclusive elastic properties by optimizing the density log and synthesizing the missing shear sonic log. The accuracy of the selected model was authenticated by statistical measures, i.e., good prediction quality, high correlation coefficient, along with less normalized root mean square error for modeled Vp, Vs and density. This comprehensive approach adheres to the interrelationship between pores, minerals, cementation effects and fluids to address reservoir heterogeneity, facies classification and tight sand. Furthermore, these parameters are translated in a ubiquitous way in the petro-elastic domain, illuminating the sweet spots within the reservoir.