scholarly journals Insights, Trends and Challenges Associated with Measuring Coal Relative Permeability

2019 ◽  
Vol 89 ◽  
pp. 01004
Author(s):  
Dylan Shaw ◽  
Peyman Mostaghimi ◽  
Furqan Hussain ◽  
Ryan T. Armstrong
Keyword(s):  
Relative Permeability ◽  
Effective Stress ◽  
History Matching ◽  
Water Saturation ◽  
Laboratory Data ◽  
Stress Regime ◽  
Cross Point ◽  
Irreducible Water Saturation ◽  
Relative Permeability Curves ◽  
The Right

Due to the poroelasticity of coal, both porosity and permeability change over the life of the field as pore pressure decreases and effective stress increases. The relative permeability also changes as the effective stress regime shifts from one state to another. This paper examines coal relative permeability trends for changes in effective stress. The unsteady-state technique was used to determine experimental relativepermeability curves, which were then corrected for capillary-end effect through history matching. A modified Brooks-Corey correlation was sufficient for generating relative permeability curves and was successfully used to history match the laboratory data. Analysis of the corrected curves indicate that as effective stress increases, gas relative permeability increases, irreducible water saturation increases and the relative permeability cross-point shifts to the right.

The Characteristics and Impacts Factors of Relative Permeability Curves in High Temperature and Low-Permeability Limestone Reservoirs

2014 ◽  
Vol 1010-1012 ◽  
pp. 1676-1683 ◽  
Author(s):  
Bin Li ◽  
Wan Fen Pu ◽  
Ke Xing Li ◽  
Hu Jia ◽  
Ke Yu Wang ◽  
...  
Keyword(s):  
Relative Permeability ◽  
Oil Recovery ◽  
Water Saturation ◽  
Phase Region ◽  
Two Phase ◽  
Experimental Conditions ◽  
Irreducible Water Saturation ◽  
Productive Water ◽  
Relative Permeability Curves ◽  
Water Cut

To improve the understanding of the influence of effective permeability, reservoir temperature and oil-water viscosity on relative permeability and oil recovery factor, core displacement experiments had been performed under several experimental conditions. Core samples used in every test were natural cores that came from Halfaya oilfield while formation fluids were simulated oil and water prepared based on analyze data of actual oil and productive water. Results from the experiments indicated that the shape of relative permeability curves, irreducible water saturation, residual oil saturation, width of two-phase region and position of isotonic point were all affected by these factors. Besides, oil recovery and water cut were also related closely to permeability, temperature and viscosity ratio.

The importance of optimal geological zonation and choice of rock parameters in dynamic reservoir simulation: a case study for the Laminaria field

2018 ◽  
Vol 58 (2) ◽  
pp. 683 ◽  
Author(s):  
Peter Behrenbruch ◽  
Tuan G. Hoang ◽  
Khang D. Bui ◽  
Minh Triet Do Huu ◽  
Tony Kennaird
Keyword(s):  
Capillary Pressure ◽  
Relative Permeability ◽  
Reservoir Simulation ◽  
History Matching ◽  
Laboratory Data ◽  
Analysis Data ◽  
Scale Model ◽  
Core Analysis ◽  
Relative Permeability Curves ◽  
Rock Parameters

The Laminaria field, located offshore in the Timor Sea, is one of Australia’s premier oil developments operated for many years by Woodside Energy Ltd. First production was achieved in 1999 using a state-of-the-art floating production storage and offloading vessel, the largest deployed in Australian waters. As is typical, dynamic reservoir simulation was used to predict reservoir performance and forecast production and ultimate recovery. Initial models, using special core analysis (SCAL) laboratory data and pseudos, covered a range of approaches, field and conceptual models. Initial coarser models also used straight-line relative permeability curves. These models were later refined during history matching. The success of simulation studies depends critically on optimal gridding, particularly vertical definition. An objective of the study presented is to demonstrate the importance of optimal and detailed vertical zonation using Routine Core Analysis data and a range of Hydraulic Flow Zone Unit models. In this regard, the performance of a fine-scale model is compared with three alternative, more traditional and coarse models. Secondly the choice of SCAL rock parameters may also have a significant impact, particularly relative permeability. This paper discusses the use of the more recently developed Carman-Kozeny based SCAL models, the Modified Carman-Kozeny Purcell (MCKP) model for capillary pressure and the 2-phase Modified Carman-Kozeny (2p-MCK) model for relative permeability. These models compare favourably with industry standard approaches, the use of Leverett J-functions for capillary pressure and the Modified Brooks-Corey model for relative permeability. The benefit of the MCK-based models is that they have better functionality and far better adherence to actual laboratory data.

Experimental Study on Effect of Temperature on Heavy Steam/Oil Relative Permeability

2014 ◽  
Vol 522-524 ◽  
pp. 1562-1566
Author(s):  
Li Ping He ◽  
Ping Ping Shen ◽  
Qi Chao Gao ◽  
Meng Chen ◽  
Xiang Yang Ma
Keyword(s):  
High Precision ◽  
Relative Permeability ◽  
Water Saturation ◽  
Laboratory Simulation ◽  
Effect Of Temperature ◽  
Oil Saturation ◽  
Steam Flooding ◽  
Irreducible Water Saturation ◽  
Relative Permeability Curves ◽  
Base Data

Because of the instability of steam and tough requirement of HTHP equipments in steam flooding laboratory simulation, it is rather difficult to obtain representative Steam/Oil relative permeability curves with high precision. In addition, although the effect of temperature on Water/Oil relative permeability curves has been studied a lot both at home and aboard, there are still some controversy perspectives, and research on temperature effect on Steam/Oil relative permeability is rare. As to the above issue, an improved steam flooding experimental method is launched to obtain accurate base data, and then simplified JBN method is applied for data processing. The Result revealed that the improved experimental methods and simplified JBN formulas can obtain representative Steam/Oil relative permeability with high precision, and temperature affects steam/oil relative permeability in various aspects, as temperature increased, oil relative permeability and irreducible water saturation increased while steam relative permeability and residual oil saturation decreased.

History Matching and Production Forecast With Logs as Effective Completion and Reservoir-Managing Tools in Horizontal and Vertical Wells

2012 ◽  
Vol 15 (05) ◽  
pp. 596-608
Author(s):  
Carlos F. Haro
Keyword(s):  
History Matching ◽  
Water Saturation ◽  
Material Balance ◽  
Reservoir Management ◽  
Production Forecast ◽  
Arrival Times ◽  
Irreducible Water Saturation ◽  
Fluid Properties ◽  
Horizontal And Vertical Wells ◽  
The Right

Summary Simulation history matching is a daunting, time-consuming task with numerous unknowns and several plausible answers. Scale differences in the data frequently obscure results, limiting its application in completion strategies. Good history matching does not guarantee accurate production forecasts, however. Reliable predictions, required for well planning, depend on the ability of the user to reduce the uncertainties to find consistent and timely solutions. Logs can provide appropriate conditioning data for history matching to enable its use for reservoir management. Electrofacies, capillary pressure, and absolute and relative permeability, imprinted on logs, can be mathematically linked with irreducible water saturation (Swi). Unlike reservoir simulators, well logs are at the right scale for completion designs. Logs facilitate upscaling, honoring rock and fluid properties and the physics of flow (Haro 2006). Logs are snapshot measurements that are amenable for conversion into dynamic forecasting tools by use of flow and pressure equations. This concept permits creation of synthetic production logs (SPLTs) over time, from which production decline can be calculated. This method consists of integrating material balance, flow/ pressure algorithms, fluid data, cores, and log data. Thus, the corresponding analytical expressions are required. In this approach, every well represents a finite, gridded tank, capable of producing a measurable volume of fluids, limited by its petrophysical constraints. Superposition, in terms of pressure and flow, combines the various components within and among wells. The quality of the results is ensured because material balance must be honored at every depth at all times under different production scenarios and the prevailing drive mechanism. This log-handling technique helps when making strategic economic decisions to maximize reserves and optimize the reservoir-development plan. This strategy is used to obtain oil in place (OIP), drainage radii, lateral connectivity, fluid-bank arrival times, productivity indices (PIs), inflow performance relationship (IPR), production allocation, and recovery per zone per well. Current log analyses or simulators generally do not provide these parameters at this detail. This refined use of logs streamlines completion designs and improves conformance, enabling us to comply with an important part of daily reservoir management.

Effect of Temperature on Oil/Water Relative Permeabilities of Unconsolidated and Consolidated Sands

1985 ◽  
Vol 25 (06) ◽  
pp. 945-953 ◽  
Author(s):  
Mark A. Miller ◽  
H.J. Ramey
Keyword(s):  
Relative Permeability ◽  
Room Temperature ◽  
Water Saturation ◽  
High Water ◽  
Distilled Water ◽  
Relative Permeabilities ◽  
Two Phase ◽  
Dynamic Displacement ◽  
Irreducible Water Saturation ◽  
Increasing Temperature

Abstract Over the past 20 years, a number of studies have reported temperature effects on two-phase relative permeabilities in porous media. Some of the reported results, however, have been contradictory. Also, observed effects have not been explained in terms of fundamental properties known to govern two-phase flow. The purpose of this study was to attempt to isolate the fundamental properties affecting two-phase relative permeabilities at elevated temperatures. Laboratory dynamic-displacement relative permeability measurements were made on unconsolidated and consolidated sand cores with water and a refined white mineral oil. Experiments were run on 2-in. [5.1-cm] -diameter, 20-in. [52.-cm] -long cores from room temperature to 300F [149C]. Unlike previous researchers, we observed essentially no changes with temperature in either residual saturations or relative permeability relationships. We concluded that previous results may have been affected by viscous previous results may have been affected by viscous instabilities, capillary end effects, and/or difficulties in maintaining material balances. Introduction Interest in measuring relative permeabilities at elevated temperatures began in the 1960's with petroleum industry interest in thermal oil recovery. Early thermal oil recovery field operations (well heaters, steam injection, in-situ combustion) indicated oil flow rate increases far in excess of what was predicted by viscosity reductions resulting from heating. This suggested that temperature affects relative permeabilities. One of the early studies of temperature effects on relative permeabilities was presented by Edmondson, who performed dynamic displacement measurements with crude performed dynamic displacement measurements with crude and white oils and distilled water in Berea sandstone cores. Edmondson reported that residual oil saturations (ROS's) (at the end of 10 PV's of water injected) decreased with increasing temperature. Relative permeability ratios decreased with temperature at high water saturations but increased with temperature at low water saturations. A series of elevated-temperature, dynamic-displacement relative permeability measurements on clean quartz and "natural" unconsolidated sands were reported by Poston et al. Like Edmondson, Poston et al. reported a decrease in the "practical" ROS (at less than 1 % oil cut) as temperature increased. Poston et al. also reported an increase in irreducible water saturation. Although irreducible water saturations decreased with decreasing temperature, they did not revert to the original room temperature values. It was assumed that the cores became increasingly water-wet with an increase in both temperature and time; measured changes of the IFT and the contact angle with temperature increase, however, were not sufficient to explain observed effects. Davidson measured dynamic-displacement relative permeability ratios on a coarse sand and gravel core with permeability ratios on a coarse sand and gravel core with white oil displaced by distilled water, nitrogen, and superheated steam at temperatures up to 540F [282C]. Starting from irreducible water saturation, relative permeability ratio curves were similar to Edmondson's. permeability ratio curves were similar to Edmondson's. Starting from 100% oil saturation, however, the curves changed significantly only at low water saturations. A troublesome aspect of Davidson's work was that he used a hydrocarbon solvent to clean the core between experiments. No mention was made of any consideration of wettability changes, which could explain large increases in irreducible water saturations observed in some runs. Sinnokrot et al. followed Poston et al.'s suggestion of increasing water-wetness and performed water/oil capillary pressure measurements on consolidated sandstone and limestone cores from room temperature up to 325F [163C]. Sinnokrot et al confirmed that, for sandstones, irreducible water saturation appeared to increase with temperature. Capillary pressures increased with temperature, and the hysteresis between drainage and imbibition curves reduced to essentially zero at 300F [149C]. With limestone cores, however, irreducible water saturations remained constant with increase in temperature, as did capillary pressure curves. Weinbrandt et al. performed dynamic displacement experiments on small (0.24 to 0.49 cu in. [4 to 8 cm3] PV) consolidated Boise sandstone cores to 175F [75C] PV) consolidated Boise sandstone cores to 175F [75C] with distilled water and white oil. Oil relative permeabilities shifted toward high water saturations with permeabilities shifted toward high water saturations with increasing temperature, while water relative permeabilities exhibited little change. Weinbrandt et al. confirmed the findings of previous studies that irreducible water saturation increases and ROS decreases with increasing temperature. SPEJ P. 945

scholarly journals Interpretation of Gas/Water Relative Permeability of Coal Using the Hybrid Bayesian-Assisted History Matching: New Insights

Energies ◽  
2021 ◽  
Vol 14 (3) ◽  
pp. 626
Author(s):  
Jiyuan Zhang ◽  
Bin Zhang ◽  
Shiqian Xu ◽  
Qihong Feng ◽  
Xianmin Zhang ◽  
...  
Keyword(s):  
Relative Permeability ◽  
Coalbed Methane ◽  
History Matching ◽  
Water Saturation ◽  
Unsteady State ◽  
Core Flooding ◽  
Rock Interaction ◽  
Interaction Mechanisms ◽  
True Value ◽  
Assisted History Matching

The relative permeability of coal to gas and water exerts a profound influence on fluid transport in coal seams in both primary and enhanced coalbed methane (ECBM) recovery processes where multiphase flow occurs. Unsteady-state core-flooding tests interpreted by the Johnson–Bossler–Naumann (JBN) method are commonly used to obtain the relative permeability of coal. However, the JBN method fails to capture multiple gas–water–coal interaction mechanisms, which inevitably results in inaccurate estimations of relative permeability. This paper proposes an improved assisted history matching framework using the Bayesian adaptive direct search (BADS) algorithm to interpret the relative permeability of coal from unsteady-state flooding test data. The validation results show that the BADS algorithm is significantly faster than previous algorithms in terms of convergence speed. The proposed method can accurately reproduce the true relative permeability curves without a presumption of the endpoint saturations given a small end-effect number of <0.56. As a comparison, the routine JBN method produces abnormal interpretation results (with the estimated connate water saturation ≈33% higher than and the endpoint water/gas relative permeability only ≈0.02 of the true value) under comparable conditions. The proposed framework is a promising computationally effective alternative to the JBN method to accurately derive relative permeability relations for gas–water–coal systems with multiple fluid–rock interaction mechanisms.

Defining irreducible water saturation using global characteristics envelopes and novel correlations

2016 ◽  
Vol 56 (1) ◽  
pp. 1 ◽  
Author(s):  
Peter Behrenbruch ◽  
Chengzhi Yuan ◽  
Nhan B. Truong ◽  
Phil Do Huu ◽  
Tuan G. Hoang
Keyword(s):  
Grain Size ◽  
Pore Structure ◽  
Water Saturation ◽  
Laboratory Data ◽  
Great Promise ◽  
Flow Zone ◽  
Structure Characteristics ◽  
Irreducible Water Saturation ◽  
Universal Correlation ◽  
Group Flow

Irreducible water saturation plays a significant role in estimating hydrocarbon initially-in-place and petroleum recovery. Yet, laboratory measurements for determining irreducible water saturation take considerable time and money. For this reason available data may not cover all requirements, giving rise to the practise of using correlations to fill in gaps. Described in this paper are the reasons for irreducible water saturation being an elusive parameter that not only depends on pore structure characteristics but also the type of experiment and laboratory procedures, as well as changing plug conditions during experimentation. This paper reviews traditional methods, as well as recent and novel approaches to quality assure laboratory data and for correlating irreducible water saturation for prediction. To gain insight into the dependence of irreducible water saturation on detailed pore structure characteristics, most notably grain size and sorting, the usefulness of global characteristics envelopes is explored (Behrenbruch and Biniwale, 2005). In this multidimensional plot, irreducible water saturation is plotted against porosity, permeability, hydraulic radius, porosity group, flow zone indicator (grain size) and sorting, giving an insightful overview of the interdependence of parameters. The second part of this paper compares novel correlations with commonly used correlations. Traditional and more recent correlations are covered, from simple correlations versus the logarithm of permeability to more sophisticated approaches using more variables, including porosity and others. Most notably, it is shown that an approach of correlating irreducible water saturation with grain size (or flow zone indicator [FZI]) and sorting shows great promise. Data from two Australian fields are used to demonstrate the methodology, showing a significant increase in fitting accuracy. This approach may eventually lead to a universal correlation.

Lowering the phase-trap damage in tight-gas reservoirs by using interfacial tension (IFT) reducers

2013 ◽  
Vol 53 (1) ◽  
pp. 363
Author(s):  
Yangfan Lu ◽  
Hassan Bahrami ◽  
Mofazzal Hossain ◽  
Ahmad Jamili ◽  
Arshad Ahmed ◽  
...  
Keyword(s):  
Relative Permeability ◽  
Reservoir Simulation ◽  
Water Saturation ◽  
Tight Gas ◽  
Gas Reservoirs ◽  
Tight Gas Reservoirs ◽  
Water Based ◽  
Tight Formations ◽  
Tight Reservoirs ◽  
Relative Permeability Curves

Tight-gas reservoirs have low permeability and significant damage. When drilling the tight formations, wellbore liquid invades the formation and increases water saturation of the near wellbore area and significantly deceases permeability of this area. Because of the invasion, the permeability of the invasion zone near the wellbore in tight-gas formations significantly decreases. This damage is mainly controlled by wettability and capillary pressure (Pc). One of the methods to improve productivity of tight-gas reservoirs is to reduce IFT between formation gas and invaded water to remove phase trapping. The invasion of wellbore liquid into tight formations can damage permeability controlled by Pc and relative permeability curves. In the case of drilling by using a water-based mud, tight formations are sensitive to the invasion damage due to the high-critical water saturation and capillary pressures. Reducing the Pc is an effective way to increase the well productivity. Using the IFT reducers, Pc effect is reduced and trapped phase can be recovered; therefore, productivity of the TGS reservoirs can be increased significantly. This study focuses on reducing phase-trapping damage in tight reservoirs by using reservoir simulation to examine the methods, such use of IFT reducers in water-based-drilled tight formations that can reduce Pc effect. The Pc and relative permeability curves are corrected based on the reduced IFT; they are then input to the reservoir simulation model to quantitatively understand how IFT reducers can help improve productivity of tight reservoirs.

Rock Typing as an Effective Tool for Permeability and Water-Saturation Modeling: A Case Study in a Clastic Reservoir in the Oriente Basin

2007 ◽  
Vol 10 (06) ◽  
pp. 730-739 ◽  
Author(s):  
Genliang Guo ◽  
Marlon A. Diaz ◽  
Francisco Jose Paz ◽  
Joe Smalley ◽  
Eric A. Waninger
Keyword(s):  
Relative Permeability ◽  
Reservoir Simulation ◽  
Water Saturation ◽  
Rock Type ◽  
Permeability Model ◽  
Initial Water ◽  
Rock Types ◽  
Rock Typing ◽  
Relative Permeability Curves ◽  
Clastic Reservoirs

Summary In clastic reservoirs in the Oriente basin, South America, the rock-quality index (RQI) and flow-zone indicator (FZI) have proved to be effective techniques for rock-type classifications. It has long been recognized that excellent permeability/porosity relationships can be obtained once the conventional core data are grouped according to their rock types. Furthermore, it was also observed from this study that the capillary pressure curves, as well as the relative permeability curves, show close relationships with the defined rock types in the basin. These results lead us to believe that if the rock type is defined properly, then a realistic permeability model, a unique set of relative permeability curves, and a consistent J function can be developed for a given rock type. The primary purpose of this paper is to demonstrate the procedure for implementing this technique in our reservoir modeling. First, conventional core data were used to define the rock types for the cored intervals. The wireline log measurements at the cored depths were extracted, normalized, and subsequently analyzed together with the calculated rock types. A mathematical model was then built to predict the rock type in uncored intervals and in uncored wells. This allows the generation of a synthetic rock-type log for all wells with modern log suites. Geostatistical techniques can then be used to populate the rock type throughout a reservoir. After rock type and porosity are populated properly, the permeability can be estimated by use of the unique permeability/porosity relationship for a given rock type. The initial water saturation for a reservoir can be estimated subsequently by use of the corresponding rock-type, porosity, and permeability models as well as the rock-type-based J functions. We observed that a global permeability multiplier became unnecessary in our reservoir-simulation models when the permeability model is constructed with this technique. Consistent initial-water-saturation models (i.e., calculated and log-measured water saturations are in excellent agreement) can be obtained when the proper J function is used for a given rock type. As a result, the uncertainty associated with volumetric calculations is greatly reduced as a more accurate initial-water-saturation model is used. The true dynamic characteristics (i.e., the flow capacity) of the reservoir are captured in the reservoir-simulation model when a more reliable permeability model is used. Introduction Rock typing is a process of classifying reservoir rocks into distinct units, each of which was deposited under similar geological conditions and has undergone similar diagenetic alterations (Gunter et al. 1997). When properly classified, a given rock type is imprinted by a unique permeability/porosity relationship, capillary pressure profile (or J function), and set of relative permeability curves (Gunter et al. 1997; Hartmann and Farina 2004; Amaefule et al. 1993). As a result, when properly applied, rock typing can lead to the accurate estimation of formation permeability in uncored intervals and in uncored wells; reliable generation of initial-water-saturation profile; and subsequently, the consistent and realistic simulation of reservoir dynamic behavior and production performance. Of the various quantitative rock-typing techniques (Gunter et al. 1997; Hartmann and Farina 2004; Amaefule et al. 1993; Porras and Campos 2001; Jennings and Lucia 2001; Rincones et al. 2000; Soto et al. 2001) presented in the literature, two techniques (RQI/FZI and Winland's R35) appear to be used more widely than the others for clastic reservoirs (Gunter et al. 1997, Amaefule et al. 1993). In the RQI/FZI approach (Amaefule et al. 1993), rock types are classified with the following three equations: [equations]

scholarly journals A CUSTOMIZED QUASI THREE-PHASE DRAINAGE RELATIVE PERMEABILITY MODEL FOR SOME INDONESIAN WATER-WET SANDSTONES

2018 ◽  
Vol 41 (1) ◽  
pp. 1-15
Author(s):  
Prof. Dr. Ir. Bambang Widarsono, M.Sc.
Keyword(s):  
Relative Permeability ◽  
Water Saturation ◽  
Measurement Data ◽  
Production Performance ◽  
Permeability Model ◽  
Reservoir Rocks ◽  
Hydrocarbon Reservoir ◽  
Three Phase ◽  
Irreducible Water Saturation ◽  
Phase Saturation

Information about drainage effective two-phase i.e. quasi three-phase relative permeability characteristics of reservoir rocks is regarded as very important in hydrocarbon reservoir modeling. The data governs various processes in reservoir such as gas cap expansion, solution gas expansion, and immiscible gas drive in enhanced oil recovery (EOR). The processes are mechanisms in reservoir that in the end determines reserves and resevoir production performance. Nevertheless, the required information is often unavailable for various reasons. This study attempts to provide solution through customizing an existing drainage relative permeability model enabling it to work for Indonesian reservoir rocks. The standard and simple Corey et al. relative permeability model is used to model 32 water-wet sandstones taken from 5 oil wells. The sandstones represent three groups of conglomeratic sandstones, micaceous-argillaceous sandstones, and hard sandstones. Special correlations of permeability irreducible water saturation and permeability ratio irreducible water saturation have also been established. Model applications on the 32 sandstones have yielded specific pore size distribution index (?) and wetting phase saturation parameter (Sm) values for the three sandstone groups, and established a practical procedure for generating drainage quasi three-phase relative permeability curves in absence of laboratory direct measurement data. Other findings such as relations between ? and permeability and influence of sample size in the modeling are also made.

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