scholarly journals Impact of Petrophysical Properties on Hydraulic Fracturing and Development in Tight Volcanic Gas Reservoirs

Geofluids ◽  
2017 ◽  
Vol 2017 ◽  
pp. 1-13 ◽  
Author(s):  
Yinghao Shen ◽  
Mianmo Meng ◽  
Tao Liu ◽  
Hongkui Ge ◽  
Yuelei Zhang
Keyword(s):  
Hydraulic Fracturing ◽  
Water Saturation ◽  
Spontaneous Imbibition ◽  
Petrophysical Properties ◽  
Gas Reservoirs ◽  
Volcanic Gas ◽  
Volcanic Reservoir ◽  
Fracturing Fluids ◽  
Irreducible Water Saturation ◽  
Fast Flow

The volcanic reservoir is an important kind of unconventional reservoir. The aqueous phase trapping (APT) appears because of fracturing fluids filtration. However, APT can be autoremoved for some wells after certain shut-in time. But there is significant distinction for different reservoirs. Experiments were performed to study the petrophysical properties of a volcanic reservoir and the spontaneous imbibition is monitored by nuclear magnetic resonance (NMR) and pulse-decay permeability. Results showed that natural cracks appear in the samples as well as high irreducible water saturation. There is a quick decrease of rock permeability once the rock contacts water. The pores filled during spontaneous imbibition are mainly the nanopores from NMR spectra. Full understanding of the mineralogical effect and sample heterogeneity benefits the selection of segments to fracturing. The fast flow-back scheme is applicable in this reservoir to minimize the damage. Because lots of water imbibed into the nanopores, the main flow channels become larger, which are beneficial to the permeability recovery after flow-back of hydraulic fracturing. This is helpful in understanding the APT autoremoval after certain shut-in time. Also, Keeping the appropriate production differential pressure is very important in achieving the long term efficient development of volcanic gas reservoirs.

scholarly journals A new model for predicting irreducible water saturation in tight gas reservoirs

2020 ◽  
Vol 17 (4) ◽  
pp. 1087-1100
Author(s):  
Yu-Liang Su ◽  
Jin-Gang Fu ◽  
Lei Li ◽  
Wen-Dong Wang ◽  
Atif Zafar ◽  
...  
Keyword(s):  
Water Saturation ◽  
Tight Gas ◽  
Gas Reservoirs ◽  
Tight Gas Reservoirs ◽  
New Model ◽  
Irreducible Water Saturation

Engineering-oriented “sweet spot” prediction for tight sandstone gas reservoirs: A case study from Sulige gas field in Western China

2020 ◽  
Vol 8 (4) ◽  
pp. T813-T821
Author(s):  
Hailiang Li ◽  
Liping Zhang ◽  
Jinyong Gui ◽  
Hailong Wang ◽  
Shengjun Li
Keyword(s):  
Hydraulic Fracturing ◽  
Young’S Modulus ◽  
Young's Modulus ◽  
Western China ◽  
Brittleness Index ◽  
Petrophysical Properties ◽  
Sweet Spot ◽  
Gas Reservoirs ◽  
Tight Sandstone ◽  
Gas Field

Tight sandstone gas reservoirs have the characteristics of low porosity and permeability, deep burial, and low production of vertical wells, which are difficult to predict and exploit. Usually, finding a “sweet spot” requires finding zones with well-developed fractures or easy stimulation by hydraulic fracturing in the later stage. For some tight sandstone gas reservoirs where natural fractures are not developed, directional hydraulic fracturing is a good choice to improve single well production. However, not all reservoirs can achieve the desired productivity after hydraulic-fracture stimulation. In the exploration of the Sulige (SLG) gas field in Western China, sweet spots with strong brittleness and good petrophysical properties can ensure the success of hydraulic fracturing. We have evaluated the SLG gas field to determine how to implement an engineering-oriented sweet spot prediction workflow. The method has five steps: data-quality analysis, lithology prediction, brittleness prediction, petrophysical property prediction, and well planning. We evaluated the feasibility of subsequent sensitive elastic parameter inversion by comparing the accrual and simulated seismic gathers. Then, we used a direct inversion method of Young’s modulus to predict lithology and identify fluid at the same time. Next, we constructed a new brittleness index by combining the rate of change of Young’s modulus and the quartz content to evaluate the brittleness of rocks, which can overcome the shortage of the conventional brittleness index constructed by a single parameter. Finally, by using the brittleness index, we combined the petrophysical properties inversion results to select regions with strong brittleness and good petrophysical properties as the basis of well planning. This workflow achieved remarkable results in the exploration of tight sandstone gas reservoirs in the SLG gas field in Western China.

Estimation of dynamic petrophysical properties of water-bearing sands invaded with oil-base mud from the interpretation of multiple borehole geophysical measurements

Geophysics ◽  
2012 ◽  
Vol 77 (6) ◽  
pp. D209-D227 ◽  
Author(s):  
Zoya Heidari ◽  
Carlos Torres-Verdín
Keyword(s):  
Capillary Pressure ◽  
Relative Permeability ◽  
Radial Distribution ◽  
Apparent Resistivity ◽  
Water Saturation ◽  
Estimation Method ◽  
Petrophysical Properties ◽  
Fluid Saturation ◽  
Irreducible Water Saturation ◽  
Geophysical Measurements

Nonmiscible fluid displacement without salt exchange takes place when oil-base mud (OBM) invades connate water-saturated rocks. This is a favorable condition for the estimation of dynamic petrophysical properties, including saturation-dependent capillary pressure. We developed and successfully tested a new method to estimate porosity, fluid saturation, permeability, capillary pressure, and relative permeability of water-bearing sands invaded with OBM from multiple borehole geophysical measurements. The estimation method simulates the process of mud-filtrate invasion to calculate the corresponding radial distribution of water saturation. Porosity, permeability, capillary pressure, and relative permeability are iteratively adjusted in the simulation of invasion until density, photoelectric factor, neutron porosity, and apparent resistivity logs are accurately reproduced with numerical simulations that honor the postinvasion radial distribution of water saturation. Examples of application include oil- and gas-bearing reservoirs that exhibit a complete capillary fluid transition between water at the bottom and hydrocarbon at irreducible water saturation at the top. We show that the estimated dynamic petrophysical properties in the water-bearing portion of the reservoir are in agreement with vertical variations of water saturation above the free water-hydrocarbon contact, thereby validating our estimation method. Additionally, it is shown that the radial distribution of water saturation inferred from apparent resistivity and nuclear logs can be used for fluid-substitution analysis of acoustic compressional and shear logs.

A Prediction of Water Breakthrough Time of Horizontal Wells in Gas Reservoirs with Bottom Water

2011 ◽  
Vol 201-203 ◽  
pp. 393-398
Author(s):  
Wei Yao Zhu ◽  
Xiao He Huang ◽  
Hong Qing Song ◽  
Jia Deng ◽  
Xuan Liu
Keyword(s):  
Bottom Water ◽  
Water Saturation ◽  
Horizontal Wells ◽  
Breakthrough Time ◽  
Gas Reservoirs ◽  
Gas Well ◽  
Porous Flow ◽  
Water Breakthrough ◽  
Irreducible Water Saturation

Based on the theory of porous flow, a study on prediction of water breakthrough time of horizontal wells in a homogeneous gas reservoir with bottom water is presented. This paper derives water breakthrough time formula of horizontal wells in a reservoir with bottom water drive. In the formula many factors are taken into account, such as height of water avoidance, gas-water mobility ratio, irreducible water saturation, residual gas saturation, etc. Case study indicates that for a horizontal gas well with constant production rate, the water breakthrough time is proportional to the height of water avoidance.

Monitoring shale gas resources in the Cooper Basin using magnetotellurics

Geophysics ◽  
2016 ◽  
Vol 81 (6) ◽  
pp. A13-A16 ◽  
Author(s):  
Nigel Rees ◽  
Simon Carter ◽  
Graham Heinson ◽  
Lars Krieger
Keyword(s):  
Hydraulic Fracturing ◽  
Shale Gas ◽  
South Australia ◽  
Depth Range ◽  
Bulk Conductivity ◽  
Gas Reservoirs ◽  
Horizontal Fracture ◽  
Fluid Permeability ◽  
Fracturing Fluids ◽  
Cooper Basin

The magnetotelluric (MT) method is introduced as a geophysical tool to monitor hydraulic fracturing of shale gas reservoirs and to help constrain how injected fluids propagate. The MT method measures the electrical resistivity of earth, which is altered by the injection of fracturing fluids. The degree to which these changes are measurable at the surface is determined by several factors, such as the conductivity and quantity of the fluid injected, the depth of the target interval, the existing pore fluid salinity, and a range of formation properties, such as porosity and permeability. From an MT monitoring survey of a shale gas hydraulic fracture in the Cooper Basin, South Australia, we have found temporal and spatial changes in MT responses above measurement error. Smooth inversions are used to compare the resistivity structure before and during hydraulic fracturing, with results showing increases in bulk conductivity of 20%–40% at a depth range coinciding with the horizontal fracture. Comparisons with microseismic data lead to the conclusion that these increases in bulk conductivity are caused by a combination of the injected fluid permeability and an increase in wider scale in situ fluid permeability.

An Approach for Exploring the Application of the Flow Zone Index Concept in Describing Petrophysical Properties Using Available SCAL Data Relative Permeability

2021 ◽  
Author(s):  
Efeoghene Enaworu ◽  
Tim Pritchard ◽  
Sarah J. Davies
Keyword(s):  
Relative Permeability ◽  
Water Saturation ◽  
Petrophysical Properties ◽  
Residual Oil ◽  
Flow Zone ◽  
Oil Saturation ◽  
Residual Oil Saturation ◽  
Core Samples ◽  
Irreducible Water Saturation ◽  
Permeability Data

Abstract This paper describes a unique approach for exploring the Flow Zone Index (FZI) concept using available relative permeability data. It proposes an innovative routine for relating the FZI parameter to saturation end-points of relative permeability data and produces a better model for relative permeability curves. In addition, this paper shows distinct wettabilities for various core samples and validated functions between FZI and residual oil saturation (Sor), irreducible water saturation (Swi), maximum oil allowed to flow (Kro, max), maximum water allowed to flow (Krw, max),and mobile/recoverable oil (100-Swi-Sor). The wettability of the core samples were defined using cross-plots of relative permeability of oil (Kro), relative permeability of water (Krw), and water saturation (Sw). After classifying the data sets into their respective wettabilities based on these criteria, a stepwise non-linear regression analysis was undertaken to develop realistic correlations between the FZI parameter, initial water saturation and end-point relative permeability parameters. In addition, a correlation using Corey's type generalised model was developed using relative permeability data, with new power law constants and well defined curves. Other parameters, including Sor, Swi, Kro, max, Krw,max and mobile oil, were plotted against FZI and correlations developed for them showed unique well behaved plots with the exception of the Sor plot. A possible theory to explain this unexpected behaviour of the FZI Vs Sor cross plot was noted and discussed. These derived functions and established relationships between the FZI term and other petrophysical parameters such as permeability, porosity, water saturation, relative permeability and residual oil saturation can be applied to other wells or reservoir models where these key parameters are already known or unknown. These distinctive established correlations could be employed in the proper characterization of a reservoir as well as predicting and ground truthing petrophysical properties.

scholarly journals Numerical Simulation of the Non-Darcy Flow Based on Random Fractal Micronetwork Model for Low Permeability Sandstone Gas Reservoirs

Geofluids ◽  
2020 ◽  
Vol 2020 ◽  
pp. 1-9
Author(s):  
Juhua Li ◽  
Chen Chen
Keyword(s):  
Fractal Dimension ◽  
Network Model ◽  
Pore Radius ◽  
Water Saturation ◽  
Darcy Flow ◽  
Gas Reservoirs ◽  
Average Pore ◽  
Fractal Method ◽  
Random Fractal ◽  
Irreducible Water Saturation

Darcy’s law is not suit for describing high velocity flow in the near wellbore region of gas reservoirs. The non-Darcy coefficient β of the Forchheimer’s equation is a main parameter for the evaluation of seepage capacity in gas reservoirs. The paper presented a new method to calculate β by performing gas and con-water flow simulations with random 3D micropore network model. Firstly, a network model is established by random fractal method. Secondly, based on the network simulation method of non-Darcy flow in the literature of Thauvin and Mohanty, a modified model is developed to describe gas non-Darcy flow with irreducible water in the porous medium. The model was verified by our experimental measurements. Then, we investigated the influence of different factors on the non-Darcy coefficient, including micropore structure (pore radius and fractal dimension), irreducible water saturation ( S wi ), tortuosity, and other reservoir characteristics. The simulation results showed that the value of the non-Darcy coefficient decreases with the increase in all: the average pore radius, fractal dimension, irreducible water saturation, and tortuosity. The non-Darcy coefficients obtained by the fractal method of microparameters are estimated more precisely than the conventional methods. The method provides theoretical support for the productivity prediction of non-Darcy flow in gas reservoirs.

Evaluation of Well Performance for the Slot-Drill Completion in Low- and Ultralow-Permeability Oil and Gas Reservoirs

SPE Journal ◽  
2014 ◽  
Vol 19 (05) ◽  
pp. 748-760 ◽  
Author(s):  
T.O.. O. Odunowo ◽  
G.J.. J. Moridis ◽  
T.A.. A. Blasingame ◽  
O.M.. M. Olorode ◽  
C.M.. M. Freeman
Keyword(s):  
Hydraulic Fracturing ◽  
Oil And Gas ◽  
Water Saturation ◽  
Low Cost ◽  
Treatment Method ◽  
Production Performance ◽  
Well Performance ◽  
Gas Formation ◽  
Irreducible Water Saturation ◽  
Ultralow Permeability

Summary Low- to ultralow-permeability formations require “special” treatments/stimulation to make them produce economical quantities of hydrocarbon, and at the moment, multistage hydraulic fracturing (MSHF) is the most commonly used stimulation method for enhancing the exploitation of these reservoirs. Recently, the slot-drill (SD) completion technique was proposed as an alternative treatment method in such formations (Carter 2009). This paper documents the results of a comprehensive numerical-simulation study conducted to evaluate the production performance of the SD technique and compare its performance to that of the standard MSHF approach. We investigated three low-permeability formations of interest—namely, a shale-gas formation, a tight-gas formation, and a tight/shale-oil formation. The simulation domains were discretized with Voronoi-gridding schemes to create representative meshes of the different reservoir and completion systems modeled in this study. The results from this study indicated that the SD method does not, in general, appear to be competitive in terms of reservoir performance and recovery compared with the more traditional MSHF method. Our findings indicate that the larger surface area to flow that results from the application of MSHF is much more significant than the higher conductivity achieved by use of the SD technique. However, there may exist cases, for example, a lack of adequate water volumes for hydraulic fracturing, or very high irreducible water saturation that leads to adverse relative permeability conditions and production performance, in which the low-cost SD method may make production feasible from an otherwise challenging (if not inaccessible) resource.

scholarly journals Performance Evaluation and Mechanism Study of a Silicone Hydrophobic Polymer for Improving Gas Reservoir Permeability

2020 ◽  
Author(s):  
Jie Zhang ◽  
Xu-Yang Yao ◽  
Bao-Jun Bai ◽  
Wang Ren
Keyword(s):  
Surface Tension ◽  
Water Saturation ◽  
Gas Production ◽  
Spontaneous Imbibition ◽  
Wettability Alteration ◽  
Mechanism Study ◽  
Gas Reservoirs ◽  
Tension Reduction ◽  
Surface Tension Reduction ◽  
Reservoir Permeability

The permeability of tight gas reservoirs is usually lower than 1 md. When the external fluids from drilling and completion processes invade such reservoirs, formation damage occurs and causes serious damage to oil and gas production. Fluorocarbon surfactants are most often recommended for removing such damage because they have extremely low surface tension, which means that they can change the reservoir wettability from water wet to gas or oil wet. However, they are not normally applied in the field because they are not cost-effective. Besides, some environmental concerns also restrict their application. In this work, we studied the effects of an oligomeric organosilicon surfactant (OSSF) on wettability modification, surface tension reduction, invasion of different fluids, and fluid flow back. It was found that the amount of spontaneous imbibition and remaining water could be reduced by the surfactant as a result of surface tension reduction and wettability alteration. Compared to the distilled water, the concentration of 0.20 wt% OSSF could decrease water saturation of cores by about 4%. At a flow-back pressure of 0.06 and 0.03 MPa after 20 PV displacement, permeability recovery could increase from 8 to 7–93% and 86%, respectively. We also found that the mechanism of OSSF includes the physical obstruction effect, surface tension reduction of external fluids, and wettability alteration of the reservoir generated. Meanwhile, quantum chemical calculations indicated that adsorbent layer of polydimethylsiloxane could decrease the affinity and adhesion of CH4 and H2O on the pore surface.

Sign in / Sign up

Export Citation Format

Share Document